Apparatus and method of enhancing the quality of high-moisture materials and separating and concentrating organic and/or non-organic material contained therein

ABSTRACT

The present invention harvests and utilizes fluidized bed drying technology and waste heat streams augmented by other available heat sources to dry feedstock or fuel. This method is useful in many industries, including coal-fired power plants. Coal is dried using the present invention before it goes to coal pulverizers and on to the furnace/boiler arrangement to improve boiler efficiency and reduce emissions. This is all completed in a low-temperature, open-air system. Also included is an apparatus for segregating particulate by density and/or size including a fluidizing bed having a particulate receiving inlet for receiving particulate to be fluidized. This is useful for segregating contaminants like sulfur and mercury from the product stream.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a divisional of U.S. Ser. No. 11/786,321 (U.S. Pat.No. 8,062,410) filed on Apr. 11, 2007;

-   -   U.S. Ser. No. 11/786,321 (U.S. Pat. No. 8,062,410) filed on Apr.        11, 2007 is a continuation-in-part of U.S. Ser. No. 11/199,743        (U.S. Pat. No. 7,540,384) filed on Aug. 8, 2005, which is a        continuation-in-part of U.S. Ser. No. 11/107,153 (U.S. Pat. No.        7,275,644) filed on Apr. 15, 2005, which claims the benefit of        U.S. provisional application Ser. No. 60/618,379 filed on Oct.        12, 2004; and is also a continuation-in-part of U.S. Ser. No.        11/199,838 filed on Aug. 8, 2005, which is a        continuation-In-part of U.S. Ser. No. 11/107,152 filed on Apr.        15, 2005, which claims the benefit of U.S. provisional        application Ser. No. 60/618,379 filed on Oct. 12, 2004;    -   all of which are hereby incorporated by reference in their        entirety.

FIELD OF THE INVENTION

This invention relates to an apparatus and method for improving thequality characteristics of high-moisture materials like coal. Morespecifically, the invention utilizes existing industrial process plantwaste heat sources in a low-temperature, open-air process to dry suchmaterials to improve their thermal content or processibility and reduceplant emissions before the particulate material is processed orcombusted at the plant. In another aspect of the invention, a scrubberassembly in operative communication with a fluidized bed is used toprocess coal or another organic material in such a manner that thedenser and/or larger material containing contaminates or otherundesirable constituents is separated from the rest of the coal or otherorganic material. While this process and scrubber assembly may beutilized in many varied industries in an efficient or economical manner,it is particularly well suited for use in electric power generationplants for reducing moisture content and sulfur, mercury, and fly ashconstituents in coal, before it is fired.

BACKGROUND OF THE INVENTION

About 63% of the world's electric power and 70% of the electric powerproduced in the United States is generated from the burning of fossilfuels like coal, oil, or natural gas at electric power plants. Such fuelis burned in a combustion chamber at the power plant to produce heatused to convert water in a boiler to steam. This steam is thensuperheated and introduced to huge steam turbines whereupon it pushesagainst the fanlike blades of the turbine to rotate a shaft. Thisspinning shaft, in turn, turns the rotor of an electric generator toproduce electricity.

Once the steam has passed through the turbine, it enters a condenserwhere it passes around pipes carrying cooling water, which absorbs heatfrom the steam. As the steam cools, it condenses into water which canthen be pumped back to the boiler to repeat the process of heating itinto steam once again. In many power plants, this water in the condenserpipes that has absorbed this heat from the steam is pumped to a spraypond or cooling tower to be cooled. The cooled water can then berecycled through the condenser or discharged into lakes, rivers, orother water bodies.

Eighty-nine percent of the coal mined in the United States is used asthe heat source for electric power plants. Unlike petroleum and naturalgas, the available supplies of coal that can be economically extractedfrom the earth are plentiful.

There are four primary types of coal: anthracite, bituminous,subbituminous, and lignite. While all four types of these coalsprincipally contain carbon, hydrogen, nitrogen, oxygen, and sulfur, aswell as moisture, the specific amounts of these solid elements andmoisture contained in coal varies widely. For example, the highestranking anthracite coals contain about 98% wt carbon, while the lowestranking lignite coals (also called “brown coal”) may only contain about30% wt carbon. At the same time, the amount of moisture may be less than1% in anthracite and bituminous coals, but 25-30% wt for subbituminouscoals like Powder River Basin (“PRB”), and 35-40% wt for North Americanlignites. For Australia and Russia, these lignite moisture levels may beas high as 50% and 60%, respectively. These high-moisture subbituminousand lignite coals have lower heating values compared with bituminous andanthracite coals because they produce a smaller amount of heat when theyare burned. Moreover, high fuel moisture affects all aspects of electricpower unit operation including performance and emissions. High fuelmoisture results in significantly lower boiler efficiencies and higherunit heat rates than is the case for higher-rank coals. The highmoisture content can also lead to problems in areas such as fuelhandling, fuel grinding, fan capacity, and high flue gas flow rates.

Bituminous coals have been the most widely used rank of coal in the U.S.for electric power production because of their abundance and relativelyhigh heating values. However, they also contain medium to high levels ofsulfur. As a result of increasingly stringent environmental regulationslike the Clean Air Act in the U.S., electric power plants have had toinstall costly scrubber devices in front of chimneys at of these plantsto prevent the sulfur dioxide (“SO₂”), nitrous oxides (“NO_(x)”), andfly ash that result from burning these coals to pollute the air.

Lower rank coals like subbituminous and lignite coals have gainedincreasing attention as heat sources for power plants because of theirlow sulfur content and cost. However, they still produce sufficientlevels of SO₂, NO_(x), and fly ash when burned such that treatment ofthe flue gas is required to comply with federal and state pollutionstandards. Additionally, ash and sulfur are the chief impuritiesappearing in coal. The ash consists principally of mineral compounds ofaluminum, calcium, iron, and silicon. Some of the sulfur in coal is alsoin the form of minerals—particularly pyrite, which is a compound of ironand sulfur. The remainder of the sulfur in coal is in the form oforganic sulfur, which is closely combined with the carbon in the coal.

It has previously been recognized within the industry that heating coalreduces its moisture, and therefore enhances the rank and heating value(BTU per pound) of the coal by drying the coal. Prior to its combustionin hot water boilers, drying of the coal can enhance the resultingefficiency of the boiler.

A wide variety of dryer devices have been used within the prior art todry coal, including rotary kilns (U.S. Pat. No. 5,103,743 issued toBerg), cascaded whirling bed dryers (U.S. Pat. No. 4,470,878 issued toPetrovic et al.), elongated slot dryers (U.S. Pat. No. 4,617,744 issuedto Siddoway et al.), hopper dryers (U.S. Pat. No. 5,033,208 issued toOhno et al.), traveling bed dryers (U.S. Pat. No. 4,606,793 issued toPetrovic et al.), and vibrating fluidized bed dryers (U.S. Pat. No.4,444,129 issued to Ladt). Also well-known within the industry arefluidized-bed dryers or reactors in which a fluidizing medium isintroduced through holes in the bottom of the bed to separate andlevitate the coal particles for improved drying performance. Thefluidizing medium may double as a direct heating medium, or else aseparate indirect heat source may be located within the fluidized bedreactor. See, e.g., U.S. Pat. No. 5,537,941 issued to Goldich; U.S. Pat.No. 5,546,875 issued to Selle et al.; U.S. Pat. No. 5,832,848 issued toReynoldson et al.; U.S. Pat. Nos. 5,830,246, 5,830,247, and 5,858,035issued to Dunlop; U.S. Pat. No. 5,637,336 issued to Kannenberg et al.;U.S. Pat. No. 5,471,955 issued to Dietz; U.S. Pat. No. 4,300,291 issuedto Heard et al.; and U.S. Pat. No. 3,687,431 issued to Parks.

Many of these conventional drying processes, however, have employed veryhigh temperatures and pressures. For example, the Bureau of Minesprocess is performed at 1500 psig, while the drying process disclosed inU.S. Pat. No. 4,052,168 issued to Koppelman requires pressures of1000-3000 psi. Similarly, U.S. Pat. No. 2,671,968 issued to Crinerteaches the use of updrafted air at 1000° F. Likewise, U.S. Pat. No.5,145,489 issued to Dunlop discloses a process for simultaneouslyimproving the fuel properties of coal and oil, wherein a reactormaintained at 850-1050° F. is employed. See also U.S. Pat. No. 3,434,932issued to Mansfield (1400-1600° F.); and U.S. Pat. No. 4,571,174 issuedto Shelton (≦1000° F.).

The use of such very high temperatures for drying or otherwise treatingthe coal requires enormous energy consumption and other capital andoperating costs that can very quickly render the use of lower-rankedcoals economically unfeasible. Moreover, higher temperatures for thedrying process create another emission stream that needs to be managedas volatiles are driven off. Further complicating this economic equationis the fact that prior art coal drying processes have often relied uponthe combustion of fossil fuels like coal, oil, or natural gas to providethe very heat source for improving the heat value of the coal to bedried. See, e.g., U.S. Pat. No. 4,533,438 issued to Michael et al.; U.S.Pat. No. 4,145,489 issued to Dunlop; U.S. Pat. No. 4,324,544 issued toBlake; U.S. Pat. No. 4,192,650 issued to Seitzer; U.S. Pat. No.4,444,129 issued to Ladt; and U.S. Pat. No. 5,103,743 issued to Berg. Insome instances, this combusted fuel source may constitute coal finesseparated and recycled within the coal drying process. See, e.g., U.S.Pat. No. 5,322,530 issued to Merriam et al; U.S. Pat. No. 4,280,418issued to Erhard; and U.S. Pat. No. 4,240,877 issued to Stahlherm et al.

Efforts have therefore been made to develop processes for drying coalusing lower temperature requirements. For example, U.S. Pat. No.3,985,516 issued to Johnson teaches a drying process for low-rank coalusing warm inert gas in a fluidized bed within the 400-500° F. range asa drying medium. U.S. Pat. No. 4,810,258 issued to Greene discloses theuse of a superheated gaseous drying medium to heat the coal to 300-450°F., although its preferred temperature and pressure is 850° F. and 0.541psi. See also U.S. Pat. Nos. 4,436,589 and 4,431,585 issued to Petrovicet al. (392° F.); U.S. Pat. No. 4,338,160 issued to Dellessard et al.(482-1202° F.); U.S. Pat. No. 4,495,710 issued to Ottoson (400-900° F.);U.S. Pat. No. 5,527,365 issued to Coleman et al. (302-572° F.); U.S.Pat. No. 5,547,549 issued to Fracas (500-600° F.); U.S. Pat. No.5,858,035 issued to Dunlop; and U.S. Pat. No. 5,904,741 and U.S. Pat.No. 6,162,265 issued to Dunlop et al. (480-600° F.).

Several prior art coal drying processes have used still lowertemperatures—albeit, only to dry the coal to a limited extent. Forexample, U.S. Pat. No. 5,830,247 issued to Dunlop discloses a processfor preparing irreversibly dried coal using a first fluidized bedreactor with a fluidized bed density of 20-40 lbs/ft³ wherein coal witha moisture content of 15-30% wt, an oxygen content of 10-20%, and a0-2-inch particle size is subjected to 150-200° F. for 1-5 minutes tosimultaneously comminute and dewater the coal. The coal is then fed to asecond fluidized bed reactor in which it is coated with mineral oil andthen subjected to a 480-600° F. temperature for 1-5 minutes to furthercomminute and dehydrate the product. Thus, it is apparent that not onlyis this process applied to coals having relatively lower moisturecontents (i.e., 15-30%), but also the coal particles are only partiallydewatered in the first fluidized bed reactor operated at 150-200° F.,and the real drying takes place in the second fluidized bed reactor thatis operated at the higher 480-600° F. bed temperature.

Likewise, U.S. Pat. No. 6,447,559 issued to Hunt teaches a process fortreating coal in an inert atmosphere to increase its rank by heating itinitially at 200-250° F. to remove its surface moisture, followed bysequentially progressive heating steps conducted at 400-750° F.,900-1100° F., 1300-1550° F., and 2000-2400° F. to eliminate the waterwithin the pores of the coal particles to produce coal with a moisturecontent and volatiles content of less than 2% and 15%, respectively, byweight. Again, it is clear that the initial 200-250° F. heating stepprovides only a limited degree of drying to the coal particles.

One of the problems that can be encountered with the use of fluidizedbed reactors to dry coal is the production of large quantities of finesentrapped in the fluidizing medium. Especially at higher bed operatingconditions, these fines can spontaneously combust to cause explosions.Therefore, many prior art coal drying processes have resorted to the useof inert fluidizing gases within an air-free fluidized bed environmentto prevent combustion. Examples of such inert gas include nitrogen,carbon dioxide, and steam. See, e.g., U.S. Pat. No. 3,090,131 issued toWaterman, Jr.; U.S. Pat. No. 4,431,485 issued to Petrovic et al.; U.S.Pat. Nos. 4,300,291 and 4,236,318 issued to Heard et al.; U.S. Pat. No.4,292,742 issued to Ekberg; U.S. Pat. No. 4,176,011 issued toKnappstein; U.S. Pat. No. 5,087,269 issued to Cha et al.; U.S. Pat. No.4,468,288 issued to Galow et al.; U.S. Pat. No. 5,327,717 issued toHauk; U.S. Pat. No. 6,447,559 issued to Hunt; and U.S. Pat. No.5,904,741 issued to Dunlop et al. U.S. Pat. No. 5,527,365 issued toColeman et al. provides a process for drying low-quality carbonaceousfuels like coal in a “mildly reducing environment” achieved through theuse of lower alkane inert gases like propane or methane. Still otherprior art processes employ a number of heated fluidizing streamsmaintained at progressively decreasing temperatures as the coal travelsthrough the length of the fluidized bed reactor to ensure adequatecooling of the coal in order to avoid explosions. See, e.g., U.S. Pat.No. 4,571,174 issued to Shelton; and U.S. Pat. No. 4,493,157 issued toWicker.

Still another problem previously encountered by the industry when dryingcoal is its natural tendency to reabsorb water moisture in ambient airconditions over time after the drying process is completed. Therefore,efforts have been made to coat the surface of the dried coal particleswith mineral oil or some other hydrocarbon product to form a barrieragainst adsorption of moisture within the pores of the coal particles.See, e.g., U.S. Pat. Nos. 5,830,246 and 5,858,035 issued to Dunlop; U.S.Pat. No. 3,985,516 issued to Johnson; and U.S. Pat. Nos. 4,705,533 and4,800,015 issued to Simmons.

In order to enhance the process economics of drying low-rank coals, itis known to use waste heat streams as supplemental heat sources to theprimary combustion fuel heat source. See U.S. Pat. No. 5,322,530 issuedto Merriam et al. This is particularly true within coking coalproduction wherein the cooling gas heated by the hot coke may berecycled for purposes of heating the drying gas in a heat exchanger.See, e.g., U.S. Pat. No. 4,053,364 issued to Poersch; U.S. Pat. No.4,308,102 issued to Wagener et al.; U.S. Pat. No. 4,338,160 issued toDellessard et al.; U.S. Pat. No. 4,354,903 issued to Weber et al.; U.S.Pat. No. 3,800,427 issued to Kemmetmueller; U.S. Pat. No. 4,533,438issued to Michael et al.; and U.S. Pat. Nos. 4,606,793 and 4,431,485issued to Petrovic et al. Likewise, flue gases from fluidized bedcombustion furnaces have been used as a supplemental heat source for aheat exchanger contained inside the fluidized bed reactor for drying thecoal. See, e.g., U.S. Pat. No. 5,537,941 issued to Goldich; and U.S.Pat. No. 5,327,717 issued to Hauk. U.S. Pat. No. 5,103,743 issued toBerg discloses a method for drying solids like wet coal in a rotary kilnwherein the dried material is gasified to produce hot gases that arethen used as the combustion heat source for radiant heaters used to drythe material within the kiln. In U.S. Pat. No. 4,284,476 issued toWagener et al., stack gas from an associated metallurgical installationis passed through hot coke in a coke production process to cool it,thereby heating the stack gas which is then used to preheat the moistcoal feed prior to its conversion into coke.

None of these prior art processes, however, appear to employ a wasteheat stream in a coal drying operation as the sole source of heat usedto dry the coal. Instead, they merely supplement the primary heat sourcewhich remains combustion of a fossil fuel like coal, oil or natural gas.Thus, the process economics for drying the coal products, includinglow-rank coals, continues to be limited by the need to burn fossil fuelsin order to dry a fossil fuel (i.e., coal) to improve its heat value forfiring a boiler in a process plant (e.g., an electric power plant).

Coal mining companies typically clean their coal products to removeimpurities before supplying them to end users like electric power plantsand coking production plants. After sorting the pieces of coal by meansof a screening device to form coarse, medium, and fine streams, thesethree coal streams are delivered to washing devices in which the coalparticles are mixed with water. Using the principle of specific gravity,the heaviest pieces containing the largest amounts of impurities settleto the bottom of the washer, whereupon they drop into a refuse bin forsubsequent disposal. The cleaned coal particles from the three streamsare then combined together again and dried by means of vibrators, jigs,or hot-air blowers to produce the final coal product ready for shipmentto the end user.

While the cleaning process employed by coal mining operations removesmuch of the ash from the coal, it has little effect on sulfur, since theorganic sulfur is closely bound to the carbon within the coal. Thus,other methods need to be used to further purify the coal prior to itscombustion. Methods are known in industry for separating different typesof particulate materials. For example, U.S. Pat. No. 3,852,168 issued toOetiker discloses a large machine for separating corn kernels from huskparts, wherein they are subjected to vibration and pulsated aircurrents. U.S. Pat. No. 5,244,099 issued to Zaltzman et al., on theother hand, teaches the delivery of granular materials through anupwardly inclined trough through which a fluidizing gas is forced fromthe bottom of the trough to create a fluidized material bed. A verticaloscillatory motion is also imparted to the trough to assist in theseparation of the various components contained in the material mixture.Less dense components of the mixture rise to the surface of thefluidized bed, while the denser components settle to the bottom. At theoutput end of the trough, a stream splitter can be used to recoverdifferent layers of materials. This apparatus is good for separatingagricultural products and sand.

It is known in the prior art that under some circumstances a fluidizedbed may be used without the addition of mechanical vibration or verticaloscillation to achieve particle separation. For example, U.S. Pat. No.4,449,483 issued to Strohmeyer uses a heated fluidized bed dryer totreat municipal trash and remove heavier particles like glass from thetrash before its combustion to produce heat. Meanwhile, U.S. Pat. No.3,539,001 issued to Binnix et al. classifies materials from an admixtureby means of intermediate selective removal of materials of predeterminedsizes and specific gravities. The material mixture travels along adownwardly sloped screen support and is suspended by upwardly directedpneumatic pulses. U.S. Pat. No. 2,512,422 issued to Fletcher et al.again uses a downwardly inclined fluidized bed with upwardly directedpulses of air, wherein small particles of coal can be separated andpurified from a coal mixture by providing holes in the top of thefluidized bed unit of a sufficient cross sectional area relative to thetotal cross sectional area of the bed to control the static pressurelevel within the fluidized bed to prevent the small particles of higherspecific gravity from rising within the coal bed.

The process and devices disclosed in these Strohmeyer, Binnix, andFletcher patents, however, all seem to be directed to the separation ofdifferent constituents within an admixture having a relatively largedifference in specific gravity. Such processes may work readily toseparate nuts, bolts, rocks, etc. from coal, however, they would not beexpected to separate coal particles containing organic sulfur from coalparticles largely free of sulfur since the specific gravities of thesetwo coal fractions can be relatively close.

Another air pollutant of great concern is mercury, which occursnaturally in coal. Regulations promulgated by the U.S. EnvironmentalProtection Agency (“EPA”) require coal-fired power plants todramatically reduce the mercury levels contained in their flue gases by2010. Major efforts within the industry have focused upon the removal ofmercury from the flue gas by the use of carbon-based sorbents oroptimization of existing flue gas emissions control technologies tocapture the mercury. However, utilization of carbon sorbent-basedserubber devices can be very expensive to install and operate. Moreover,currently existing emissions control equipment can work less well forhigh-rank coals (anthracite and bituminous) vs. low-rank coals(subbitumionous and lignite).

Western Research Institute has therefore developed and patented apre-combustion thermal process for treating low-rank coals to remove themercury. Using a two-zone reactor, the raw coal is heated in the firstzone at approximately 300° F. to remove moisture which is purged fromthe zone with a sweep gas. The dried coal is then transferred to asecond zone where the temperature is raised to approximately 550° F. Upto 70-80% of the mercury contained in the coal is volatilized and sweptfrom the zone with a second sweep gas stream. The mercury issubsequently separated from the sweep gas and collected for disposal.See Guffey, F. D. & Bland, A. E., “Thermal Pretreatment of Low-RankedCoal for Control of Mercury Emissions,” 85 Fuel Processing Technology521-31 (2004); Merriam, N. W., “Removal of Mercury from Powder RiverBasin Coal by Low-Temperature Thermal Treatment,” Topical ReportWRI-93-R021 (1993); U.S. Pat. No. 5,403,365 issued to Merriam et al.

However, this pre-combustion thermal pretreatment process is stillcapital-intensive in that it requires a dual zone reactor to effectuatethe drying and mercury volatilization steps. Moreover, an energy sourceis required to produce the 550° F. bed temperature. Furthermore, 20-30%of the mercury cannot be removed from the coal by this process, becauseit is tightly bound to the carbon contained in the coal. Thus, expensivescrubber technology will still be required to treat flue gas resultingfrom combustion of coal pretreated by this method because of theappreciable levels of mercury remaining in the coal after completion ofthis thermal pre-treatment process.

Therefore, the ability to pre-treat particulate material like coal witha fluidized bed operated at a very low temperature without mechanical orchemical additives in order to separate and remove most of the pollutantconstituents within the coal (e.g., mercury and sulfur) would bedesirable. Such a process could be applied to all ranks of coal, andwould alleviate the need for expensive scrubber technology for treatmentof flue gases after combustion of the coal.

The concerted use of waste heat sources available within industrialplants using boilers that would otherwise be lost as the exclusive heatsource for drying the coal prior to its introduction to the boilerfurnace to improve the process economics of using low-rank coals likesubbituminous and lignite coal would also be desirable. Such low-rankcoal sources could suddenly become viable fuel sources for power plantscompared with the more traditionally used bituminous and anthracitecoals. The economical use of lower-sulfur subbituminous and lignitecoals, in addition to removal of undesirable elements found within thecoal that causes pollution, would also be greatly beneficial to theenvironment.

SUMMARY OF THE INVENTION

A method for enhancing the quality characteristics of materials used asan essential component in an industrial plant operation through the useof waste heat sources available in that plant operation is providedaccording to the invention. Such materials can include fuel sourcescombusted within the industrial plant operation, or raw materials usedto make the finished products resulting from the plant operation. Suchwaste heat sources include, but are not limited to, hot flue or stackgases from furnaces, hot condenser cooling water or air, process steamfrom turbines, and other process streams with elevated heat values. Thepresent invention relates in particular to the process for identifyingand exploiting the various available waste heat sources, alone or incombination, to provide heat of appropriate magnitude and temperaturelevel that is needed to enhance the quality or characteristic of thematerial.

Although the invention has application to many varied industries andparticulate materials, for illustrative purposes, the invention isdescribed herein with respect to a typical coal-burning electric powergenerating plant, where removal of some of the moisture from the coal ina dryer is desirable for improving the heat value of the coal and theresulting boiler efficiency of the plant. Drying coal in this manner canenhance or even enable the use of low-rank coals like subbituminous andlignite coals. By reducing the moisture content of the coal, regardlessof whether it constitutes low-rank or high-rank coal, other enhancedoperating efficiencies may be realized, as well. For example, drier coalwill reduce the burden on the coal handling system, conveyers and coalcrushers in the electric generating plant. Since drier coal is easier toconvey, this reduces maintenance costs and increases availability of thecoal handling system. Drier coal is also easier to pulverize, so less“mill” power is needed to achieve the same grind size (coal fineness).With less fuel moisture, moisture content leaving the mill is reduced.This will improve the results of grinding of the coal. Additionally,less primary air used to convey, fluidize, and heat the coal is needed.Such lower levels of primary air reduces air velocities and with lowerprimary air velocities, there is a significant reduction of erosion incoal mills, coal transfer pipes, coal burners, and associated equipment.This has the effect of reducing coal transfer pipe and mill maintenancecosts, which are, for lignite-fired plants, very high. Reductions instack emissions should also be realized, thereby improving collectionefficiency of downstream environmental protection equipment.

Such coal fuel stock need not be dried to absolute zero moisture levelsin order to fire the power plant boilers on an economically viablebasis. Instead, by using such available waste heat sources to dry thecoal to a sufficient level, the boiler efficiency can be markedlyincreased, while maintaining the processing costs at an economicallyviable level. This provides true economic advantage to the plantoperator. Reduction of the moisture content of lignite coals from atypical 39-60% level to 10% or lower is possible, although 27-32% ispreferable. This preferred level is dictated by the mass transfer limitfor the boilers transferring heat to superheat and reheat the steam sentto the turbines.

The present invention preferably utilizes multiple plant waste heatsources in various combinations to dry the material without adverseconsequences to plant operations. In a typical power plant, wasteprocess heat remains available from many sources for further use. Onepossible source is a steam turbine. Steam may be extracted from thesteam turbine cycle to dry coal. For many existing turbines, this couldreduce power output and have an adverse impact on performance of turbinestages downstream from the extraction point, making this source for heatextraction of limited desirability. For newly built power plants,however, steam turbines are designed for steam extraction without havinga negative effect on stage efficiency, thereby enabling such steamextraction to be a part of the waste heat source used for coal dryingfor new plants.

Another possible source of waste heat for drying coal is the thermalenergy contained within flue gas leaving the plant. Using the waste heatcontained in flue gas to remove coal moisture may decrease stacktemperature, which in turn reduces buoyancy in the stack and couldresult in condensation of water vapor and sulfuric acid on stack walls.This limits the amount of heat that could be harvested from flue gas forcoal drying, especially for units equipped with wet scrubbers, which maythereby dictate that hot flue gas is not the sole waste heat source usedin many end-use applications under this invention.

In a Rankine power cycle, heat is rejected from the cycle in the steamcondenser and/or cooling tower. Heat rejected in a steam condensertypically used in utility plants represents a large source of wasteheat, the use of which for a secondary purpose minimally impacts plantoperation. A portion of this hot condenser cooling water leaving thecondenser could therefore be diverted and used instead for coal drying.Engineering analyses show that, at full unit load, only two percent ofthe heat rejected in the condenser is needed to decrease coal moisturecontent by four percentage points. Utilization of this heat source,solely or in combination with other available plant waste heat sources,provides optimal use of plant waste heat sources without adverse impacton plant operations.

While this invention focuses upon the use of available waste heatsources to enable the moisture reduction or other processing step, itshould be appreciated that a primary heat source like combustion heatmay be added to the system for utilizing waste heat sources to achievethe desired result on an economic basis. Typically, this will be a smallamount of primary heat relative to the waste heat sources used.

The present invention utilizes fixed bed dryers and fluidized beddryers, both single and multiple-stage, to pre-dry and further clean thematerial before it is consumed within the industrial plant operation,although other commercially known types of dryers may be employed.Moreover, this drying process takes place in a low-temperature, open-airsystem, thereby further reducing the operating costs for the industrialplant. The drying temperature may advantageously be kept below 300° F.,more preferably between 200-300° F.

With the present invention, a portion of the hot condenser cooling waterleaving the condenser could be diverted and used for preheating theinlet air directed to the APH.

The present invention also includes an apparatus for segregatingparticulate material by density and/or size and concentrating pollutantslike fly ash, sulfur, and mercury-bearing materials, or otherundesirable constituents for separation from the particulate materialfeed. In contrast to current prior art systems that attempt to removethe pollutants and other contaminants after the coal is burned, theapparatus of the present invention includes a fluidizing bed having areceiving inlet for receiving the particulate material to be fluidized.The fluidized bed also includes an opening for receiving a firstfluidizing stream, which can be a primary heat stream, a secondary heatstream, at least one waste stream, or any combination thereof. At leastone discharge outlet is provided on the fluidized bed for dischargingthe desirable fluidized particulate stream, as well as at least onedischarge outlet for discharging the non-fluidized particulate streamcontaining a concentration of the pollutant or other undesirableconstituents. A conveyor is operatively disposed within the fluidizedbed for conveying the non-fluidized particulates to the non-fluidizedparticulate discharge outlet. A collector box is in operativecommunication with the fluidized bed for receiving the dischargednon-fluidized particulate material stream. There is also an optionalmeans within the collector box for directing a second fluidizing streamthrough the non-fluidized particulate material while it is in thecollector box in order to further concentrate the pollutants or otherundesirable constituents contained therein.

Removal of such pollutants and other contaminants before the coal isburned eliminates potential harm that may be caused to the environmentby the contaminants in the plant processes, with the expected benefitsof lower emissions, coal input levels, auxiliary power needs to operatethe plant, plant water usage, equipment maintenance costs caused bymetal erosion and other factors, and capital costs arising fromequipment needed to extract these contaminants from the flue gas.

One advantage of the present invention is that it permits generallycontinuous processing of the particulate material. As the non-fluidizedparticulate stream is discharged from the fluidized bed, moreparticulate material feed can be added to the fluidized bed forprocessing.

Another advantage of the present invention is a generally horizontalconveyance of the non-particulate material. This generally horizontalconveyance of the non-fluidized particulate material ensures that all ofthe particulate material is processed evenly and quickly by mixing orchurning the material while it is being conveyed.

Yet another advantage of the present invention is that it permits thesegregation of contaminants and their removal from a particulatematerial feed. This can provide a significant environmental benefit foran industrial plant operation.

Still yet another advantage of the present invention is that it includesa second fluidizing step or apparatus to capture more non-contaminatedfluidizable particulates that are still trapped, or have become trapped,in the non-fluidized particulate material. Capturing more of thefluidized particulate increases the amount of usable non-contaminatedparticulates, while reducing the amount of contaminated particulatesthat will be subject to further processing or disposal. By capturingmore of the usable non-contaminated particulates and reducing the amountof contaminated particulate material, a company is able to increase itsefficiency while reducing its costs.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings:

FIG. 1 is a schematic diagram illustrating a simplified coal-fired powerplant operation for producing electricity.

FIG. 2 is a schematic diagram showing an improved coal-fired powerplant, which utilizes the flue gas and steam turbine waste heat streamsto enhance the boiler efficiency.

FIG. 3 is a view of a fluidized-bed dryer of the present invention andits associated equipment for conveying coal and hot fluidizing air.

FIG. 4 is a schematic-diagram of a single-stage fluidized-bed dryer ofthe present invention.

FIG. 5 is a plan view of a distributor plate for the fluidized-bed dryerof the present invention.

FIG. 6 is a plan view of another embodiment of the distributor plate forthe fluidized-bed dryer.

FIG. 7 is a view of the distributor plate taken along line 7-7 of FIG.6.

FIG. 8 is a plan view of the distributor plate of FIG. 6 containing ascrew auger.

FIG. 9 is a schematic diagram of a single-stage fluidized-bed dryer ofthe present invention that utilizes a primary heat source to heatindirectly the fluidizing air used both the dry and fluidize the coal.

FIG. 10 is a schematic diagram of a single-stage fluidized bed dryer ofthe present invention that utilizes waste process heat to indirectlyheat the fluidizing air used both to dry and fluidize the coal.

FIG. 11 is a schematic diagram of a single-stage fluidized bed dryer ofthe present invention that utilizes a combination of waste process heatto heat the fluidizing air used to fluidize the coal (indirect heat),and hot condenser cooling water circulated through an in-bed heatexchanger contained inside the fluidized bed dryer to dry the coal(direct heat).

FIG. 12 is a schematic diagram of a single-stage fluidized bed dryer ofthe present invention that utilizes a combination of waste process heatto heat the fluidizing air used to fluidize the coal (indirect heat),and hot steam extracted from a steam turbine cycle and circulatedthrough an in-bed heat exchanger contained inside the fluidized beddryer to dry the coal (direct heat).

FIG. 13 is a schematic diagram of a single-stage fluidized bed dryer ofthe present invention that utilizes waste process heat to both heat thefluidizing air used to fluidize the coal (indirect heat), and to heatthe transfer liquid circulated through an in-bed heat exchangercontained inside the fluidized bed dryer to dry the coal (indirectheat).

FIG. 14 is a schematic diagram of a single-stage fluidized bed dryer ofthe present invention that utilizes hot flue gas from a plant furnacestack to both heat the fluidizing air used to fluidize the coal(indirect heat), and to heat the transfer liquid circulated through anin-bed heat exchanger contained inside the fluidized bed dryer to drythe coal (indirect heat).

FIG. 15 is a view of a two-stage fluidized-bed dryer of the presentinvention.

FIG. 16 is a schematic diagram of a two-stage fluidized bed dryer of thepresent invention that utilizes waste process heat from the plantoperations to heat the fluidizing air used to fluidize the coal in bothchambers of the fluidized bed dryer (indirect), and hot condensercooling water circulated through in-bed heat exchangers contained insideboth chambers of the fluidized bed dryer to dry the coal (direct heat).

FIG. 17. is a side view of the heating coils employed within the dryerbed.

FIG. 18 is a view of the heating coils taken along line 18-18 of FIG.17.

FIG. 19 is a schematic diagram of a fluidized bed dryer in combinationwith means for separating contaminates from coal fines.

FIG. 20 is a schematic diagram of a fluidized bed dryer in combinationwith means for separating contaminates from coal fines and burning thecontaminates to generate power.

FIGS. 21 a and 21 b are perspective cut-away views of the scrubberassembly used to remove segregation stream particulate from thefluidized-bed dryer.

FIG. 22 is perspective view of another scrubber assembly embodiment ofthe present invention.

FIG. 23 is a plan view of the scrubber assembly of FIG. 22.

FIG. 24 is an enlarged perspective view of a portion of the scrubberassembly shown in FIG. 22.

FIG. 25 is an end view of a gate or material flow regulator of ascrubber assembly according to an example embodiment of the presentinvention.

FIG. 26 is a cross section view of the gate according to an exampleembodiment of the present invention.

FIG. 27 is a cross-sectional view of a window assembly.

FIG. 28 is a schematic of a two-stage fluidized-bed pilot dryer of thepresent invention.

FIGS. 29-30 are graphical depictions of several operationalcharacteristics of the fluidized-bed dryer of FIG. 28.

FIG. 31 is a schematic diagram of a two-stage fluidized bed dryer of thepresent invention integrated into an electric power plant that uses hotcondenser cooling water to heat the coal contained in the first dryerstage, and to heat the fluidizing air used to fluidize the coal in bothdryer stages. The hot condenser cooling water in combination with hotflue gas dries the coal in the second dryer stage.

FIG. 32 is a schematic diagram of a two-stage fluidized bed dryer of thepresent invention integrated into an electric power plant that uses thecombined waste heat provided by the hot condenser cooling water and hotflue gas to heat and/or dry the coal in both dryer stages.

FIG. 33 is a schematic diagram a two-stage fluidized bed dryer of thepresent invention integrated into an electric power plant that uses thehot flue gas to heat and/or dry the coal in both dryer stages.

FIG. 34 is a schematic diagram of a further preferred embodiment of atwo-stage fluidized bed dryer integrated into an electric power plantthat uses hot condenser cooling water and hot flue gas to heat thefluidizing airstreams for the dryer and provide a heat source to theinbed heat exchangers located within the dryer.

FIG. 35 is another variation upon the low-temperature drying processutilizing waste heat sources of FIG. 34 further comprising a coalpreheater and a dried coal cooler.

FIG. 36 is a schematic diagram of a coal cooler of the presentinvention.

FIG. 37 a is a view of a weir gate located within the fluidized beddryer leading to an integrated coal cooler stage.

FIG. 37 b is a view of the discharge gates of the coal cooler stage.

FIG. 37 c is a partial view of the coal cooler discharge end wall anddischarge gate.

FIG. 38 illustrates a closed-cooling circuit with a tri-sector airpre-heater.

FIG. 39 illustrates a closed-cooling circuit with a bisector airpre-heater.

FIG. 40 illustrates an open-cooling circuit with a tri-sector rotatingregenerative air pre-heater.

FIG. 41 illustrates a second embodiment of an open-cooling circuit witha tri-sector rotating regenerative air pre-heater.

FIG. 42 is a schematic diagram of one embodiment of a fixed bed dryer.

FIG. 43 is a graphical depiction of the improvement in net unit heatrate of coal at different moisture levels.

FIG. 44 is a graphical depiction of the HHV value of coal at differentmoisture levels.

FIG. 45 is a schematic diagram of Configuration A (base case) of thisinvention.

FIG. 46 is a schematic diagram of Configuration B (high temperature) ofthis invention.

FIG. 47 is a schematic diagram of Configuration C (low temperature) ofthis invention.

FIG. 48 is a schematic diagram of Configuration D (ultra-lowtemperature) of this invention.

FIG. 49-59 are graphical depictions of different measures of power plantefficiency for coals at different moisture levels using the various coaldrying configurations.

FIG. 60 is a schematic diagram of the prototype dryer system of thepresent invention.

FIGS. 61-73 are graphical depictions of different measures ofperformance for the prototype dryer.

FIGS. 74-75 are mercury mass balances around the fluidized bed dryer.

FIG. 76 is a graphical depiction of the effect of flue gas moisturecontent and residence time on mercury speciation.

The foregoing summary and are provided for example purposes only and areamenable to various modifications and arrangements that fall within thespirit and scope of the present invention. Therefore, the figures shouldnot be considered limiting, but rather as a supplement to aid oneskilled in the art to understand the novel concepts that are included inthe following detailed description.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

A method for enhancing the quality characteristics of materials used asan essential component in an industrial plant operation through the useof one or more waste heat sources available in the plant operation isprovided by the invention. Such invention allows for the drying of thematerial on a more economic basis, thereby enabling the use oflower-ranked (e.g., higher moisture) material that might not otherwisebe viable within the industrial plant operation. The invention may alsoenable reductions in pollutants and other undesirable elements containedwithin the material before it is processed within the industrial plantoperation.

The invention also includes an apparatus for, and a method of,separating a particulate material feed stream into a fluidizedparticulate stream having reduced levels of pollutants or otherundesirable constituents (“contaminants”), and a non-fluidizedparticulate stream formed from denser and/or larger particles having anincreased concentration of the contaminants. The method of separationutilized in the present invention capitalizes on the physicalcharacteristics of the contaminants. In particular, it capitalizes onthe difference between the specific gravity of contaminated andnon-contaminated material. The contaminants can be removed from amajority of the particulate material by separating and removing thedenser and/or larger material in which such contaminants areconcentrated. The present invention uses a fluidization method ofseparating the contaminated denser and/or larger material from thenon-contaminated material.

For purposes of the present invention, “particulate material” means anygranular or particle compound, substance, element, or ingredient thatconstitutes an integral input to an industrial plant operation,including but not limited to combustion fuels like coal, biomass, bark,peat, forestry waste matter, corn stover, and switch grass;refuse-derived fuels like garbage; bauxite and other ores; andsubstrates to be modified or transformed within the industrial plantoperation like grains, cereals, malt, cocoa, and paper pulps.

In the context of the present invention, “industrial plant operation”means any combustion, consumption, transformation, modification, orimprovement of a substance to provide a beneficial result or endproduct. Such operation can include but is not limited to electric powerplants; coking operations; iron, steel, or aluminum manufacturingfacilities; cement manufacturing operations; glass manufacturing plants;ethanol production plants; drying operations for grains and otheragricultural materials, and biomass materials like corn stover, switchgrass, bark and peat; food processing facilities; refuse-derived fuelcombustion plants; pulping mills; and heating operations for factoriesand buildings. Industrial plant operations encompass other manufacturingoperations incorporating heat treatment of a product or system,including but not limited to green houses, district heating,regeneration processes for amines or other extractants used in carbondioxide or organic acid sequestration, and synthetic fuels production,including coal liquification.

As used in this application, “coal” means anthracite, bituminous,subbituminous, and lignite or “brown” coals, and peat. Powder RiverBasin coal is specifically included.

For purposes of the present invention, “quality characteristic” means adistinguishing attribute of the particulate material that impacts itscombustion, consumption, transformation, modification, or improvementwithin the industrial plant operation, including but not limited tomoisture content, carbon content, sulfur content, mercury content, flyash content, and production of SO₂ and NO_(x), carbon dioxide, mercuryoxide when burned.

As used in this application, “heat treatment apparatus” means anyapparatus that is useful for the application of heat to a product,including but not limited to furnaces, dryers, cookers, ovens,incubators, growth chambers, and heaters.

In the context of the present invention, “dryer” means any apparatusthat is useful for the reduction of the moisture content of aparticulate material through the application of direct or indirect heat,including but not limited to a fluidized bed dryer, vibratory fluidizedbed dryer, fixed bed dryer, traveling bed dryer, cascaded whirling beddryer, elongated slot dryer, hopper dryer, or kiln. Such dryers may alsoconsist of single or multiple vessels, single or multiple stages, bestacked or unstacked, and contain internal or external heat exchangers.

For purposes of this application “principal heat source” means aquantity of heat produced directly for the principal purpose ofperforming work in a piece of equipment, such as a boiler, turbine,oven, furnace, dryer, heat exchanger, reactor, or distillation column.Examples of such a principal heat source include but are not limited tocombustion heat and process steam directly exiting a boiler.

As used in this application, “waste heat source” means any residualgaseous or liquid by-product stream having an elevated heat contentresulting from work already performed by a principal heat source withina piece of equipment within an industrial plant operation that is usedfor the secondary purpose of performing work in a piece of equipmentinstead of being discarded. Examples of such waste heat sources includebut are not limited to cooling water streams, hot condenser coolingwater, hot condenser cooling air, hot flue or stack gas, spent processsteam from, e.g., a turbine, or discarded heat from operating equipmentlike a compressor, reactor, or distillation column.

For purposes of this application, “contaminant” means any pollutant orother undesirable element, compound, chemical, or constituent containedwithin a particulate material that it is desirable to separate from orreduce its presence within the particulate material prior to its use,consumption, or combustion within an industrial plant operation.

Although the present invention may be used in a variety of end-useapplications, such as in farming, manufacturing, or industrial plantoperations, for illustrative purposes only, the invention is describedherein with respect to coal-burning electric power generating plantsthat utilize fluidized dry beds to dry the coal feed. This is not meantto limit in any way the application of the apparatus and method of thisinvention to other appropriate or desirable end-use applications outsideof coal or the electric power generation industry.

For background purposes, FIG. 1 shows a simplified coal-fired electricpower plant 10 for the generation of electricity. Raw coal 12 iscollected in a coal bunker 14 and is then fed by means of feeder 16 to acoal mill 18 in which it is pulverized to an appropriate orpredetermined particle size as is known in the art with the assistanceof primary air stream 20. The pulverized coal particles are then fed tofurnace 25 in which they are combusted in conjunction with secondary airstream 30 to produce a heat source. Flue gas 27 is also produced by thecombustion reaction. The flue gas 27 is subsequently transported to thestack via environmental equipment.

This heat source from the furnace, in turn, converts water 31 intangentially wall-fired boiler 32 into steam 33, which is delivered tosteam turbine 34. Steam turbine 34 may consist more fully of highpressure steam turbine 36, intermediate pressure steam turbine 38, andlow pressure steam turbines 40 operatively connected in series. Steam 33performs work by pushing against the fan-like blades connected to aseries of wheels contained within each turbine unit which are mounted ona shaft. As the steam pushes against the blades, it causes both thewheels and turbine shaft to spin. This spinning shaft turns the rotor ofelectric generator 43, thereby producing electricity 45.

Steam 47 leaving the low-pressure steam turbines 40 is delivered tocondenser 50 in which it is cooled by means of cooling water 52 toconvert the steam into water. Most steam condensers are water-cooled,where either an open or closed-cooling circuit is used. In theclosed-loop arrangement show in FIG. 1, the latent heat contained withinthe steam 47 will increase the temperature of cold cooling water 52, sothat it is discharged from steam condenser 50 as hot cooling water 54,which is subsequently cooled in cooling tower 56 for recycle as coldcooling water 52 in a closed-loop arrangement. In an open-coolingcircuit, on the other hand, the heat carried by cooling water isrejected into a cooling body of water (e.g., a river or a lake). In aclosed-cooling circuit, by contrast, the heat carried by cooling wateris rejected into a cooling tower.

Note that other condensers are air-cooled. The heated air produced bysuch cooling step could be used as a waste heat source within theprocess of the present invention.

The operational efficiency of the electric power plant 10 of FIG. 1 maybe enhanced by extracting and utilizing some of the waste heat andbyproduct streams of the electricity power plant, as illustrated in FIG.2. Fossil-fired plant boilers are typically equipped with airpre-heaters (“APH”) utilized to heat primary and secondary air streamsused in the coal milling and burning process. Burned coal is used in aboiler system (furnace, burner and boiler arrangement) to convert waterto steam, which is then used to operate steam turbines that areoperatively connected to electrical generators. Heat exchangers, oftentermed steam-to-air pre-heaters (“SAH”), use steam extracted from thesteam turbine to preheat these primary and secondary air streamsupstream of the air pre-heater. Steam extraction from the turbineresults in a reduced turbine (and plant) output and decreases the cycleand unit heat rate.

A typical APH could be of a regenerative (Ljungstrom or Rothemule) or atubular design. The SAHs are used to maintain elevated temperature ofair at an APH inlet and protect a cold end of the APH from corrosioncaused by the deposition of sulfuric acid on APH heat transfer surfaces,and from plugging which results in an increase in flow resistance andfan power requirements. A higher APH inlet air temperature results in ahigher APH gas outlet temperature and higher temperature of APH heattransfer surfaces (heat transfer passages in the regenerative APH, ortubes in a tubular APH) in the cold end of the APH. Higher temperaturesreduce the acid deposition zone within the APH and also reduce the aciddeposition rate.

Thus, within the modified system 65, SAH 70 uses a portion 71 of thespent process steam extracted from intermediate-pressure steam turbine38 to preheat primary air stream 20 and secondary air stream 30 beforethey are delivered to coal mill 18 and furnace 25, respectively. Themaximum temperature of primary air stream 20 and secondary air stream 30which can be achieved in SAH 70 is limited by the temperature ofextracted steam 71 exiting steam turbine 38 and the thermal resistanceof SAH 70. Moreover, primary air stream 20 and secondary air stream 30are fed by means of PA fan 72 and FD fan 74, respectively, to tri-sectorAPH 76, wherein these air streams are further heated by means of fluegas stream 27 before it is discharged to the atmosphere. In this manner,primary air stream 20 and secondary air stream 30 with their elevatedtemperatures enhance the efficiency of the operation of coal mill 18 andproduction of process heat in furnace 25. Furthermore, the condensate 78discharged by condenser 50 may be recycled to boiler 32 to be convertedinto process steam once again. Flue gas 27 and process steam 71 exitingsteam turbine 38 and the condensate 78 exiting the condenser which mightotherwise go to waste have been successfully used to enhance the overallefficiency of the electric power generating plant 65.

As discussed above, it would further benefit the operational efficiencyof the electric generating plant if the moisture level of coal 12 couldbe reduced prior to its delivery to furnace 25. Such a preliminarydrying process could also enable the use of lower-rank coals likesubbituminous and lignite coals on an economic basis.

Application U.S. Ser. No. 11/199,838, entitled “Apparatus for HeatTreatment of Particulate Materials” filed on Aug. 8, 2005, which sharesa common co-inventor and owner with the present application, disclosesin greater detail fluidized-bed dryers and other dryer apparati that canbe used in conjunction with the present invention, and is herebyincorporated by reference in its entirety. Nevertheless, the followingdetails regarding the fluidized bed and segregating means are disclosedherein.

FIG. 3 shows a fluidized bed dryer 100 used as the fluidized bedapparatus for purposes of separating the fluidized coal particle streamand the non-fluidized particle stream, although it should be understoodthat any other type of dryer may be used within the context of thisinvention. Moreover, the entire fluidized bed apparatus system mayconsist of multiple coal dryers connected in series or parallel toremove moisture from the coal. A multi-dryer approach, involving anumber of identical coal drying units, provides operating andmaintenance flexibility and, because of its generally smaller sizerequirements, allows coal dryers to be installed and integrated withinexisting power plant equipment, as well as in stages, one at a time.This will minimize interference with normal plant operations.

The fluidized bed(s) will operate in open air at relativelylow-temperature ranges. An in-bed heat exchanger will be used inconjunction with a stationary fluidized-bed or fixed-bed design toprovide additional heat for coal drying and, thus, reduce the necessaryequipment size. With a sufficient in-bed heat transfer surface in afluidized bed dryer, the fluidizing/drying air stream can be reduced tovalues corresponding to the minimum fluidization velocity. This willreduce erosion damage to and elutriation rate for the dryer.

Heat for the in-bed heat exchanger can be supplied either directly orindirectly. A direct heat supply involves diverting a portion of hotfluidizing air stream, hot condenser cooling water, hot condensercooling air, process steam, hot flue gas, or other waste heat sourcesand passing it through the in-bed heat exchanger. An indirect heatsupply involves use of water or other heat transfer liquid, which isheated by hot primary air stream, hot condenser cooling water, hotcondenser cooling air, steam extracted from steam turbine cycle, hotflue gas, or other waste heat sources in an external heat exchangerbefore it is passed through the in-bed heat exchanger.

The bed volume can be unitary or divided into several sections, referredto herein as “stages.” A fluidized-bed dryer is a good choice fortreating sized coal to be burned at the same site where the coal is tobe combusted. The multiple stages could be contained in a single vesselor multiple vessels. A multi-stage design allows maximum utilization offluidized-bed mixing, segregation, and drying characteristics. The coaldryer may include a direct or indirect heat source for drying the coal.

FIG. 3 discloses a coal dryer in the form of a fluidized-bed dryer 100and associated equipment at an industrial plant site. Wet coal 12 isstored in bunker 14 whereupon it is released by means of feed gate 15 tovibrating feeder 16 which transports it to coal mill 18 to pulverize thecoal particles. The pulverized coal particles are then passed throughscreen 102 to properly size the particles to less than ¼ inch indiameter. The sized pulverized coal particles are then transported bymeans of conveyor 104 to the upper region of the fluidized-bed dryer 100in which the coals particles are fluidized and dried by means of hot air160. The dried coal particles are then conveyed by lower dry coalconveyor 108, bucket elevator 110, and upper dry coal conveyor 112 tothe top of dried coal bunkers 114 and 116 in which the dried coalparticles are stored until needed by the boiler furnace 25.

Moist air and elutriated fines 120 within the fluidized-bed dryer 100are transported to the dust collector 122 (also known as a “baghouse”)in which elutriated fines are separated from the moist air. Dustcollector 122 provides the force for pulling the moist air andelutriated fires into the dust collector. Finally, the air cleaned ofthe elutriated fines is passed through stack 126 for subsequenttreatment within a scrubber unit (not shown) of other contaminants likesulfur, NO_(x), and mercury contained within the air stream.

FIG. 4 discloses an embodiment of a coal drying bed under the presentinvention that is a single-stage, single-vessel, fluidized-bed dryer 150with a direct heat supply. While there are many different possiblearrangements for the fluidized-bed dryer 150, common functional elementsinclude a vessel 152 for supporting coal for fluidization and transport.The vessel 152 may be a trough, closed container, or other suitablearrangement. The vessel 152 includes a distributor plate 154 that formsa floor towards the bottom of vessel 152, and divides the vessel 154into a fluidized bed region 156 and a plenum region 158. As shown inFIG. 5, the distributor plate 154 may be perforated or constructed withsuitable valve means to permit fluidizing air 160 to enter the plenumregion 158 of vessel 152. The fluidizing air 160 is distributedthroughout the plenum region 158 and forced upwards through the openings155 or valves in the distributor plate 154 at high pressure to fluidizethe coal 12 lying within the fluidized bed region 156.

An upper portion of vessel 152 defines a freeboard region 162. Wet sizedcoal 12 enters the fluidized bed region 156 of fluidized bed dryer 150through entry point 164, as shown in FIG. 4. When the wet sized coal 12is fluidized by fluidizing air 160, the coal moisture and elutriatedcoal fines are propelled through the freeboard region 162 of vessel 152and exit the vessel typically at the top of the fluidized-bed dryer 150at vent outlet points 166, as shown. Meanwhile, fluidized coal product168 will exit the vessel 152 via discharge chute 170 to a conveyor 172for transport to a storage bin or furnace boiler. As the fluidized coalparticles move across the fluidized bed region 156 above the distributorplate 154 in the direction A shown in FIG. 4, they will build up againstweir 174 which constitutes a wall traversing the width of thefluidized-bed dryer. The height of the weir 174 will define the maximumthickness of the fluidized-bed of coal particles within the dryer, foras the accumulated coal particles rise above the height of the weir,they will necessarily pass over the top of the weir and fall into aregion of the fluidized-bed dryer 150 adjacent to the discharge chute170. Meanwhile, the larger and denser coal particles (“segregationstream”) will naturally gravitate towards the bottom of the fluidizedbed 156 due to their higher specific gravity. A conveyor means 178described more fully herein will push or otherwise transfer thesenon-fluidized segregation stream coal particles through a dischargeoutlet 179, so they exit the fluidized bed. The structure and locationof the coal inlet 164 and outlet points 169 and 179, the elutriatedfines outlet 166, the distributor plate 154, and configuration of thevessel 152 may be modified as desired for best results.

Fluidized-bed dryer 150 preferably includes a wet bed rotary airlock 176operationally connected to wet coal inlet 164 maintaining a pressureseal between the coal feed and the dryer, while permitting introductionof the wet coal feed 12 to the fluidized bed 156. Rotary airlock 176should have a housing of cast iron construction with a nickel-carbidecoated bore. The end plates of the airlock should be of cast ironconstruction with a nickel-carbide coated face. Airlock rotors should beof cast iron construction with closed end, leveled tips, and satellitewelded. In an embodiment of the invention, airlock 176 should be sizedto handle approximately 115 tons/hour of wet coal feed, and shouldrotate at approximately 13 RPM at 60% fill to meet this sizingcriterion. The airlock is supplied with a 3-hp inverter duty gear motorand an air purge kit. While airlock 176 is directly connected to themotor, any additional airlocks provided at additional wet coal inlets tothe fluidized-bed dryer can be chain driven. Note that an appropriatecoating material like nickel carbide is used on cast iron surfaces ofthe airlock that are likely to suffer over time from passage of theabrasive coal particles. This coating material also provides a“non-stick surface” to the airlock parts that come into contact with thecoal particles.

A product rotary airlock 178 is supplied air in operative connection tothe fluidized-bed dryer outlet point 169 to handle the dried coalproduct 168 as it exits the dryer. In an embodiment of the invention,airlock 178 should have a housing of cast iron construction with anickel-carbide coated bore. Airlock end plates should likewise be ofcast iron construction with a nickel-carbide coated face. The airlockrotor should be of cast iron construction with a closed end, leveledtips, and satellite welded. The airlock should preferably rotate atapproximately 19 RPM at 60% fill to meet the sizing criterion. Theairlock should be supplied with a 2-hp inverter duty generator, chaindrive, and air purge kit.

Distributor plate 154 separates the hot air inlet plenum 158 from thefluidized-bed drying chambers 156 and 162. The distributor plate shouldpreferably be fabricated from ⅜-inch thick water jet drilled 50,000psi-yield carbon steel as shown in FIG. 5. The distributor plate 154 maybe flat and be positioned in a horizontal plane with respect to thefluidized-bed dryer 150. The openings 155 should be approximately ⅛-inchin diameter and be drilled on approximately 1-inch centers from feed endto discharge end of the distributor plate, ½-inch center across, and ina perpendicular orientation with respect to the distributor plate. Morepreferably, the openings 155 may be drilled in approximately a65°-directional orientation with respect to the distributor plate sothat the fluidizing air 160 forced through the opening 155 in thedistributor plate blows the fluidized coal particles within thefluidized-bed region 156 towards the center of the dryer unit and awayfrom the side walls. The fluidized coal particles travel in direction Bshown in FIG. 5. Such a flat, planar distributor plate 154 would workwell where the conveyor means 178 is a belt, ram, drag chain, or othersimilar device located in the fluidized bed above the distributor plate.

Another embodiment of the distributor plate 180 is shown in FIGS. 6-7.Instead of a flat planar plate, this distributor plate 180 consists oftwo drilled plates 182 and 184 that have flat portions 182 a and 184 b,rounded portions 182 b and 184 b, and vertical portions 182 c and 184 c,respectively. The two vertical portions 182 c and 184 c are boltedtogether by means of bolts 186 and nuts 188 in order to form thedistributor plate unit 180. “Flat” portions 182 a and 184 a of thedistributor plate 180 are actually installed on a 5° slope towards themiddle of the dryer unit in order to encourage the coal particles toflow towards the center of the distributor plate. Meanwhile, roundedportions 182 b and 184 b of the distributor plate units cooperate todefine a half-circle region 190 approximately one foot in diameter foraccommodating a screw auger 194, as shown more clearly in FIG. 8. Thedrilled openings 183 and 185 in the distributor plate units 182 and 184,respectively, will once again be on an approximately 1-inch centers fromthe feed end to the discharge end and ½-inch center across, having a65°-directional slope with respect to the horizontal plane of the dryerunit). While the flat portions 182 a and 184 a and vertical portions 182a and 184 c of the distributor plate units 182 and 184 should be madefrom ⅜-inch thick water jet drilled 50,000 psi-yield carbon steel, therounded portions 182 b and 184 b will preferably be formed from ½-inchthick carbon steel for increased strength around the screw trough 190.Fluidized coal particles travel in direction C shown in FIG. 6.

A screw auger 194 is positioned within the trough region 190 of thedistributor plate, as shown on FIG. 8. This screw auger should have a12-inch diameter, be sized for 11.5 tons/hour removal of the oversizedcoal particles in the dryer bed, and have sufficient torque to startunder a 4-foot thick deep bed of coal particles. The drive will be a3-hp inverter duty motor with a 10:1 turndown. The screw auger 194should be of carbon steel construction for durability.

The trough 190 of the distributor plate 180 and screw auger 194 shouldbe perpendicular to the longitudinal direction of the dryer. Thisenables the fins 196 of the screw auger during operation to engage thesegregation stream coal particles along the bottom of the fluidized coalbed and push them out the discharge outlet 179 of the fluidized beddryer.

FIG. 9 discloses the fluidized bed dryer 150 of FIG. 4 in schematicform, wherein the same numbers have been used for the correspondingdryer parts for ease of understanding. Ambient air 160 is drawn by meansof a fan 200 through a heater 202 heated by a combustion source 204. Aportion of the fluidizing air 206, heated by circulation through heater202, is directed to the fluidized bed region 156 for fluidizing the wetsized coal 12. Any suitable combustion source like coal, oil, or naturalgas may be used for heater 202.

While such heated fluidizing air 206 can be used to heat the coalparticles 12 that are fluidized within the bed region 156 and evaporatewater on the surface of the particles by conductive heat transfer withthe heated fluidizing air, an inbed heat exchanger 208 is preferablyincluded within the dryer bed to provide heat conduction to the coalparticles to further enhance this heating and drying process. A directheat supply is created by diverting the remainder of the fluidizing hotair 206 (heated by heater 202) through in-bed heat exchanger 208, whichextends throughout the fluidized bed 156, to heat the fluidized coal todrive out moisture. The fluidizing air 206 exiting the in-bed heatexchanger 208 is recycled back to fan 200 to once again be circulatedthrough and heated by the heater 202. Some loss of fluidizing air 206results when fluidizing air directly enters the fluidized bed region 156through plenum 158. This lost air is replaced by drawing further ambientair 160 into the circulation cycle.

FIG. 10 illustrates another embodiment of the single-stage,single-vessel, fluidized bed dryer 150 of FIG. 4 except that an externalheat exchanger 210 is substituted for heater 202, and waste process heat212 from the surrounding industrial process plant is used to heat thisexternal heat exchanger. Because industrial process plants likeelectricity generation plants typically have available waste processheat sources that would otherwise be discarded, this configuration ofthe present invention enables the productive use of this waste processheat to heat and dry the wet coal 12 in the fluidized bed dryer 150 inorder to enhance the boiler efficiencies from the combustion of suchdried coal on a more commercially viable basis. The use of a primaryheat source like coal, oil, or natural gas, as shown in FIG. 9, is amore expensive option for drying the coal particles.

FIG. 11 illustrates yet another embodiment of a single-stage,single-vessel, fluidized bed dryer 220 that is similar to the one shownin FIG. 10, except that the waste process heat 212 is not used to heatboth the external heat exchanger 210 and the in-bed heat exchanger 208.Instead, a portion of the hot condenser cooling water 222 from elsewherein the electricity generation plant operation is diverted to in-bed heatexchanger 208 to provide the necessary heat source. Thus, in thefluidized dryer embodiment 220 of FIG. 11, two separate waste heatsources (i.e., waste process heat and hot condenser cooling water) areemployed to enhance the operational efficiency of the coal dryingprocess.

FIG. 12 shows still another embodiment of a single-stage, single-vessel,fluidized bed dryer 230 similar to the one depicted in FIG. 11, exceptthat hot process steam 232 extracted from the steam turbines of theelectricity power plant is used instead of hot condenser cooling wateras a heat source for in-bed heat exchanger 208. Again, fluidized beddryer 230 uses two different waste heat sources (i.e., waste processheat 212 and hot process steam 232) in order to enhance the operatingefficiency of the coal drying process.

Another embodiment of a fluidized bed dryer is shown in FIGS. 13-14,entailing a single-stage, single-vessel, fluidized bed dryer 240 with anindirect heat supply. An indirect heat supply to the in-bed heatexchanger 208 is provided by the use of water or other heat transferliquid 242, which is heated by the fluidizing air 206, hot condensercooling water 222, process steam 232 extracted from the steam turbinecycle, or hot flue gas 248 from the furnace stack in an external heatexchanger 210, and then circulated through the in-bed heat exchanger 208by means of pump 246, as illustrated in FIG. 13. Any combination ofthese sources of heat (and other sources) may also be utilized.

Still another embodiment of an open-air, low-temperature fluidized beddryer design of the present invention is illustrated in FIGS. 15-16,which is a multiple-stage, single-vessel, fluidized bed dryer 250 with adirect heat supply (hot condenser cooling water 252 from the coolingtower of electric power plant) to an in-bed heat exchanger 208. Vessel152 is divided in two stages: a first stage 254 and second stage 256.Although illustrated in FIGS. 15-16 as a two-stage dryer, additionalstages may be added and further processing can be achieved. Typically,wet sized coal 12 enters the first stage 254 of the fluidized bed drier250 through the freeboard region 162 at entry point 164. The wet sizedcoal 12 is preheated and partially dried (i.e., a portion of surfacemoisture is removed) by hot condenser cooling water 252 entering,circulating and exiting through the heating coils of in-bed heatexchanger 258 contained inside the first stage 254 (direct heat). Thewet sized coal 12 is also heated and fluidized by hot fluidizing air206. Fluidizing air 206 is forced by fan 200 through the distributorplate 154 of the first stage 254 of the fluidized bed dryer 250 afterbeing heated by waste process heat 212 in external heat exchanger 210.

In the first stage 254, the hot fluidization air stream 206 is forcedthrough the wet sized coal 12 supported by and above distributor plate154 to dry the coal and separate the fluidizable particles andnon-fluidizable particles contained within the coal. Heavier or denser,non-fluidizable particles segregate out within the bed and collect atits bottom on the distributor plate 154. These non-fluidizable particles(“segregation stream”) are then discharged from the first stage 254 asStream 1 (260). Fluidized bed dryers are generally designed to handlenon-fluidized material up to four inches thick collecting at the bottomof the fluidized bed. The non-fluidized material may account for up to25% of the coal input stream. This segregation stream 260 can bedirected through another beneficiation process or simply be rejected.Movement of the segregated material along the distributor plate 154 tothe discharge point for stream 260 is accomplished by an inclinedhorizontal-directional distributor plate 154, as shown in FIG. 16. Thefirst stage 254 therefore separates the fluidizable and non-fluidizablematerial, pre-dries and preheats the wet sized coal 12, and providesuniform flow of the wet sized coal 12 to the second stage 256 containedwithin the fluidized bed dryer 250. From the first stage 254, thefluidized coal 12 flows airborne over a first weir 262 to the secondstage 256 of the bed dryer 250. In this second stage of the bed dryer250, the fluidized coal 12 is further heated and dried to a desiredoutlet moisture level by direct heat, hot condenser cooling water 252entering, circulating, and exiting the heating coils of the in-bed heatexchanger 264 contained within the second stage 256 to radiate sensibleheat therein. The coal 12 is also heated, dried, and fluidized by hotfluidizing air 206 forced by fan 200 through the distributor plate 154into the second stage 256 of the fluidized bed dryer 250 after beingheated by waste process heat 212 in external heat exchanger 210.

The dried coal stream is discharged airborne over a second weir 266 atthe discharge end 169 of the fluidized bed dryer 250, and elutriatedfines 166 and moist air are discharged through the top of the dryerunit. This second stage 256 can also be used to further separate fly ashand other impurities from the coal 12. Segregated material will beremoved from the second stage 256 via multiple extraction points 268 and270 located at the bottom of the bed 250 (or wherever else that isappropriate), as shown in FIG. 16 as Streams 2 (268) and 3 (270). Therequired number of extraction points may be modified depending upon thesize and other properties of the wet sized coal 12, including withoutlimitation, nature of the undesirable impurities, fluidizationparameters, and bed design. The movement of the segregated material tothe discharge point(s) 260, 268, and 270 can be accomplished by aninclined distributor plate 154 shown in FIG. 16, or by existingcommercially available horizontal-directional distributor plates.Segregation streams 1, 2 and 3 may be either removed from the processand land-filled or further processed to remove undesirable impurities.

The fluidization air stream 206 is cooled and humidified as it flowsthrough the coal bed 250 and wet sized coal 12 contained in both thefirst stage 254 and second stage 256 of the fluidized bed 156. Thequantity of moisture which can be removed from the coal 12 inside thedryer bed is limited by the drying capacity of the fluidization airstream 206. Therefore, the heat inputted to the fluidized bed 156 bymeans of the heating coils of the in-bed heat exchangers 258 and 264increases the drying capacity of fluidizing air stream 206, and reducesthe quantity of drying air required to accomplish a desired degree ofcoal drying. With a sufficient in-bed heat transfer surface, drying airstream 206 could be reduced to values corresponding to the minimumfluidization velocity needed to keep particulate suspended. This istypically in the 0.8 meters/second range, but the rate could beincreased to run at a higher value, such as 1.4 meters/second, to assurethat the process never drops below the minimum required velocity.

To achieve maximum drying efficiency, drying air stream 206 leavesfluidized bed 156 at saturation condition (i.e., with 100% relativehumidity). To prevent condensation of moisture in the freeboard region162 of the fluidized bed dryer 250 and further downstream, coal dryer250 is designed for outlet relative humidity less than 100%. Also, aportion of the hot fluidizing air 206 may be bypassed around thefluidized bed 156, and mixed with the saturated air in the freeboardregion 162 to lower its relative humidity (e.g., sparging), as explainedmore fully herein. Alternatively, reheat surfaces may be added insidethe freeboard region 162 of the fluidized bed dryer 250 or heating ofvessel skin, or other techniques may be utilized to increase thetemperature and lower the relative humidity of fluidization air 206leaving the bed dryer 250, and prevent downstream condensation. Themoisture removed in the dryer is directly proportional to the heat inputcontained in the fluidizing air and heat radiated by the in-bed heatexchangers. Higher heat inputs result in higher bed and exittemperatures, which increase the water transport capabilities of theair, thereby lowering the required air-to-coal ratio required to achievethe desired degree of drying. The power requirements for drying aredependent upon the air flow and the fan differential pressure. Theability to add heat in the dryer bed is dependant upon the temperaturedifferential between the bed and heating water, the heat transfercoefficient, and the surface area of the heat exchanger. In order to uselower temperature waste heat, more heat transfer area is thereforeneeded to introduce the heat into the process. This typically means adeeper bed to provide the necessary volume for the heat coils of thein-bed heat exchangers. Thus, intended goals may dictate the precisedimensions and design configuration of the fluidized bed dryer of thepresent invention.

Coal streams going into and out of the dryer include the wet sized coal12, processed coal stream, elutriated fines stream 166, and thesegregation streams 260, 268, and 270. To deal with the non-fluidizablecoal, the dryer 250 is equipped with a screw auger 194 contained withinthe trough region 190 of first-stage distributor plate 180 inassociation with a collection hopper and scrubber unit for collectingthe segregation stream coal particles, as disclosed more fully herein.

Typical associated components of a dryer include, amongst others, coaldelivery equipment, coal storage bunker, fluidized bed dryer, airdelivery and heating system, in-bed heat exchanger(s), environmentalcontrols (dust collector), instrumentation, and a control and dataacquisition system. In one embodiment, screw augers are used for feedingmoist coal into and extracting the dried coal product out of the dryer.Vane feeders can be used to control the feed rates and provide an airlock on the coal streams into and out of the dryer. Load cells on thecoal bunker provide the flow rate and total coal input into the dryer.Instrumentation could include, without limitation, thermocouples,pressure gauges, air humidity meters, flow meters and strain gauges.

With respect to fluidized-bed dryers, the first stage accomplishespre-heating and separation of non-fluidizable material. This can bedesigned as a high-velocity, small chamber to separate the coal. In thesecond stage, coal dries by evaporation of coal moisture due to thedifference in the partial pressures between the water vapor and coal. Ina preferred embodiment, most of the moisture is removed in the secondstage.

The heating coils 280 contained within the in-bed heat exchanges 258 and264 of fluidized-bed dryer 250 are shown more clearly in FIGS. 17-18.Each heating coil is of carbon steel construction consisting of atwo-pass, U-tube coil connection 282 with an integral water box 284connected thereto with a cover, inlet flange 286, outlet flange 288, andlifting lugs 290. These heating coil bundles are designed for 150 psigat 300° F. with 150# ANSI flanges for the water inlet 286 and outlet288. The heating coil tubes 280 are oriented across the width of thefirst-stage 254 and second-stage 256 of the dryer unit, and supportplates 292 with lifting lugs are interspaced along the length of theheating coil bundles to provide lateral support.

An embodiment of the first-stage heat exchanger 258 contains 50 heatingcoil pipes (280) having a 1½-inch diameter with Sch 40 SA-214 carbonsteel finned pipe, ½-inch-high fins, and ½-inch fin pitch×16-garagesolid helical-welded carbon steel fins with a 1-inch horizontalclearances and a 1½-inch diagonal clearance. The second-stage heatexchanger 264, meanwhile, can consist of one long set of tube bundles,or multiple sets of tube bundles in series, depending upon the length ofthe second stage of the dryer. The tubes of the second-stage heatexchanger 264 will generally consist of 1½-inch OD tubing×10 BWG wallSA-214 carbon steel finned pipe, ¼-½-inch-high fins, and ½-¾-inch finpitch×16-gauge solid helical-welded carbon steel fins with 1-inchhorizontal clearance and 1½-inch diagonal clearance. In an embodiment ofthis invention, the second-stage heating coil pipes contain 110-140tubes running the length of the second stage. The combined surface areaof the tube bundles for both the first-stage and second-stage heatexchangers 258 and 264 is approximately 8,483 ft².

The heat source provided to the fluidized bed under the presentinvention may be primary heat. More preferably, the heat source shouldbe a waste heat source like hot condenser cooling water, hot condensercooling air, hot water drain, process waste heat, hot flue gas, or spentturbine steam, which may be used alone or in combination with anotherwaste heat source(s) or primary heat. Such waste heat sources aretypically available in many if not most industrial plant operations, andtherefore may be used to operate the low-temperature processing andcontaminant separation process of the present invention on a morecommercially economical basis, instead of being discarded within theindustrial plant operation. U.S. Ser. No. 11/107,152 filed on Apr. 15,2005, which shares a common co-inventor and owner with this application,describes more fully how to integrate such primary or waste heat sourcesinto the fluidized bed apparatus, and is incorporated hereby byreference in its entirety.

The dryer bed designs for this invention are intended to be customdesigned to maximize use of waste heat streams available from a varietyof power plant processes without exposing the coal to temperaturesgreater than 300° F., preferably between 200-300° F. (Other feedstock orfuel temperature gradients and fluid flows will vary, depending upon theintended goal to be achieved, properties of the fuel or feedstock andother factors relevant to the desired result). Above 300° F., typicallycloser to 400° F., oxidation occurs and volatiles are driven out of thecoal, producing another stream containing undesirable constituents thatneed to be managed (e.g., SO₂ and mercury, and other potential problemsfor the plant operations.

The dryers are able to handle higher-temperature waste heat sources bytempering the air input to the dryer to less than 300° F. and inputtingthis heat into heat exchanger coils within the bed. The multi-stagedesign of a fluidized-bed dryer creates temperature zones which can beused to achieve more efficient heat transfer by counter flowing of theheating medium. The coal outlet temperature from a dryer bed isrelatively low (typically less than 140° F.) and produces a productwhich is relatively easy to store and handle. If a particularparticulate material requires a lower or higher product temperature, thedryers can be designed to provide the reduced or increased temperature.

Selection of appropriate dryer design, dryer temperature, and residencetime for the coal contained within the bed will produce a reduction inmoisture to the desired level. For low-rank coals for power plantapplications, this may entail a moisture reduction for North Americanlignite from approximately 35-40% wt to 10-35% wt, more preferably27-32% wt. In other geographical markets like Australia and Russia thatstart out with high moisture levels for lignite as high as 50-60% wt,coal users may choose to reduce the moisture level through drying tobelow 27%. wt For subbituminous coals, this moisture reduction might befrom approximately 25-30% wt to approximately 10-30% wt, more preferably20-25% wt. While properly designed dryer processes under this inventioncan reduce the moisture level of particulate materials to 0% usinglow-temperature heat, in the case of coal for electric power plantoperations, this may be unnecessary and increase processing costs.Custom designs permit the beds to be constructed to dry high-moisturecoal to a level best suited for the particular power plant process.

Many possible implementation options are available for use of thelow-temperature, open-air dry process utilizing waste heat options ofthe present invention within an industrial plant operation. A preferredembodiment is shown in FIG. 31 in the form of a two-stage, single-vesselfluidized bed dryer 302 integrated within an electrical power generationplant 300, using hot condenser cooling water 304 and hot flue gas 306 asthe sole heat sources for the drying operation. Raw lignite coal 12having a moisture level of 35-40% wt is fed into a screen 310 to sortthe coal for suitable size for handling within the process.Appropriately sized coal 12 within the range of two inch minus, morepreferably 0.25 inches or less, is conveyed by standard means directlyinto preprocess coal storage bin 312. Any oversized coal greater than0.25 inches is first run through a crusher 314 before it is conveyed bystandard means to coal storage bin 312.

From the storage bin, the wet, sized coal 12 is then transported by aconveyor system known within the art to the fluidized bed dry 302,wherein the total moisture on the surface of and within the pores of thecoal particles is reduced to a predetermined level to yield “dried” coal316 having an average moisture level of approximately 28-30% wt. Thisresulting dried coal 316 is transported by conveyor 318 to bucketelevator 320 to dry coal storage hopper 322 where it is kept untilneeded for the boiler furnace.

The dried coal 316 collected in storage hopper 322 is conveyed byconventional means to coal mill 324 in which it is pulverized intodried, pulverized coal 326 prior to being conveyed to wind box 328 forentry into furnace 330. For purposes of this application, the processparameters typical of “winter conditions” in North Dakota for a 4million lbs/hr boiler capacity are provided for the coal drying processshown in FIG. 31. Upon combustion of the coal 326 in furnace 330, theresulting heat within the 6 billion BTU/hr range is transferred to water332 contained in boiler 334. Steam 336 at an average temperature of1000° F. and pressure of 2,520 psig. is then passed onto the first of aseries of high-pressure, intermediate-pressure, and low-pressure steamturbines (not shown) used to drive at least one generator (not shown)for the production of electricity. The spent steam will typically leavethe high-pressure turbine at 600° F. and 650 psi, and leave thedownstream intermediate pressure turbine(s) at approximately 550-600° F.and 70 psi.

The spent steam 338 exiting the low-pressure turbine at approximately125-130° F. and 1.5 psia is thereafter delivered to condenser 340wherein it is converted to water. Cold cooling water 342 atapproximately 85° F. is circulated through condenser 340 to withdrawlatent heat energy from the spent steam 338. In the process, the coolingwater 342 will become hotter and exits the condenser as hot coolingwater 344 at approximately 120° F. This hot condenser cooling water 344is then passed to cooling tower 346 wherein its temperature is reducedagain to approximately 85° F. to produce the cold condenser coolingwater for recycle to condenser 340. The condensate from the condenser isthereafter re-circulated through boiler 334 to be reheated into steam336 for use again to drive the steam turbine.

Fluidized bed dryer 302 consists of first stage 350 having adistribution area of 70 ft² for receiving the coal 12 to be dried, and alarger second stage 352 having a distribution area of 245 ft². Thesestages of the fluidized bed dryer 302 are equipped with in-bed heatexchangers 354 and 356, respectively, which will be discussed in greaterdetail below.

A portion 304 of the hot condenser cooling water is diverted andcirculated through heat exchanger 354 to provide the direct source ofheat to the first stage 350 of the dryer. This hot condenser coolingwater 304 will typically average 120° F., and causes first-stage in-bedheat exchanger to emit 2.5 million BTU/hr of heat. The spent hotcondenser cooling water 358 exiting the heat exchanger at approximately100° F. returns indirectly to the condenser whereupon it will assist inthe cooling down of the spent turbine steam 358, and become hotcondenser cooling water 304 once again.

A portion 304 a of the hot condenser cooling water is circulated throughexternal heat exchanger 360, which is used to heat up the glycol-basedcirculation fluid 362 used to heat preliminary fan room coil 364. Thispreliminary fan room coil 364 increases the temperature of primary airstream 366 and secondary air stream 368 from ambient temperature, whichwill vary throughout the time of year, to approximately 25-30° F.(winter conditions). Glycol will not freeze at low temperatures, so itensures that the primary and secondary air streams likewise will notfall below a minimum temperature of 25° F.

Primary air stream 366 and secondary air stream 368 leaving preliminaryfan room coil 364 are then passed onto the principal fan room coil 370,which constitutes an air-water heat exchanger unit. A portion 304 b ofhot condenser cooling water 304 is circulated through principal fan roomcoil 370 to provide the necessary heat source. The primary air stream366 and secondary air stream 368 exit primary fan room coil atapproximately 80-100° F., whereupon they are conveyed by means of PA fan372 and FD. fan 374, at 140° F. and 112° F., respectively, to externalair heater 376, which constitutes a tri-sector, rotating regenerativeair pre-heater.

The use of the fanroom coils 364 and 370 to preheat inlet air to the airpreheater 376 and the hot and cold primary air streams 380 and 366 a,respectively, increases the temperature of the heat available to theouter heat exchanger 386 and heat transfer fluid stream 388 from the120° F. range to the 200° F.-plus range. This has a positive effect onthe flow rate of fluidizing/drying air 382 and on the required surfacearea of the in-bed heat exchanger 302. Both are reduced as thetemperature of drying and heating streams is increased.

A portion 366 a of the primary air 366 is diverted prior to external airpre-heater 376 to mixing box 378 at approximately 145° F. After mixingwith a hotter stream 380 a (at approximately 283° F.) of the primaryair, it forms fluidizing air 382 at approximately 187° F., which is usedas the fluidizing medium for both first stage 350 and second stage 352of fluidized bed dryer 302. In order to achieve this 187° F. fluidizingair temperature, approximately 54% of the air entering mixing box 378will be provided by hot PA air 380 a, and approximately 46% will beprovided by cold PA air 366 a. The fluidizing air 382 will enter firststage 350 at velocity of approximately 3.5 ft/sec to fluidize theapproximately 40 inch-thick bed of coal particles. The coal particles 12travel across the first stage 350 at approximately 132,000 lbs/hr,wherein they are heated by in-bed heat exchanger 354 and the fluidizingair to approximately 92° F. and undergo a small moisture reduction. Uponreaching the end of the first stage 350, they will spill over the top ofa weir into second stage 352.

Flue gas 306 exits the boiler furnace 330 at approximately 825° F. Thiswaste heat source is passed through external air heater 376 to providethe heating medium. The flue gas exits the external heater atapproximately 343° F. and is vented to the stack via a precipitator andscrubber. But, in the process, the flue gas heats primary air stream 366and secondary air stream 368 to approximately 757° F. and 740° F.,respectively, to form hot primary air 380 and heated secondary air 382.The heated secondary air stream 382 is delivered to furnace 330 atapproximately 117% of what is needed to aid the combustion process andenhance the boiler efficiency.

Hot primary air 380 at approximately 757° F. is delivered to coal mill324, whereupon it forms a source of positive pressure to push thepulverized coal particles to wind box 328 and furnace 330. Again,preheating the pulverized coal particles 326 in this manner enhances theboiler efficiency and enables the use of a smaller boiler and associatedequipment.

With drier coal, the flame temperature is higher due to lower moistureevaporation loss, and the heat transfer processes in the furnace 330 aremodified. The higher flame temperature results in larger radiation heatflux to the walls of furnace 330. Since the moisture content of theexiting flue gas 306 is reduced, radiation properties of the flame arechanged, which also affects radiation flux to the walls of furnace 330.With higher flame temperature, the temperature of coal ash particlesexiting the furnace 330 is higher, which could increase furnace foulingand slagging. Deposition of slag on furnace walls reduces heat transferand results in a higher flue gas temperature (“FEGT”) at the furnaceexit. Due to reduction in coal flow rate as fuel moisture is reduced,the amount of ash entering the boiler will also be reduced. This reducessolid particle erosion in the boiler 334 and maintenance of the boiler334 (e.g., the required removal of the soot that collects on theinterior surface of the boiler).

A portion of the hot primary air stream 380 is diverted to heatexchanger 386, which heats a liquid medium 388 to approximately 201° F.,which is used as the heat source for in-bed heat exchanger 356 containedin second stage 352 of the fluidized bed dryer 302. This liquid mediumwill leave the heat exchanger at approximately 160° F. whereupon it isrouted back to heat exchanger 386 to be reheated. As already mentionedabove, primary air stream 380 a leaving heat exchanger 386 atapproximately 283° F. combines with cold primary air 366 a in mixing box378 to form the fluidizing air stream 382 directed to the fluidized beddryer 302. This mixing box allows the temperature of the fluidizing airto be adjusted to a desired level

The fluidized coal particles that were delivered from first stage 350 atapproximately 92° F. and slightly reduced moisture to second stage 352of the fluidized bed dryer will form a bed of approximately 38-42 inchesin depth that will be fluidized by air stream 382 and further heated byin-bed heat exchanger 356. These coal particles will take approximately12 minutes to travel the length of the second stage 352 of the fluidizedbed, whereupon they will be discharged as dried coal 316 atapproximately 118° F. and 29.5% wt moisture. More importantly, the heatvalue of the coal 12 that entered the first stage of dryer 302 atapproximately 6200 BTU/lb has been increased to approximately 7045BTU/lb.

Within the industry, an “X ratio” is calculated to represent therelative efficiency of the transfer of heat across air preheater 376from flue gas 306 to primary air 366 and secondary air 368. Representedby the equation:m _(PA+FD) ·cp _(PA+FD)·(T _(out) −T _(in))_(PA+FD) =m _(flue) ·cp_(flue)·(T _(in) −T _(out))_(flue)

-   -   where m is the mass flow, cp is the specific heat, T_(in) is the        inlet temperature, and T_(out) is the outlet temperature for the        respective combustion air (i.e., primary air and secondary air)        and flue gas streams, respectively. Because the product of        (m·cp) for the combustion air stream (stated in BTU/hr) is        typically only 80% of the corresponding value for the flue gas        stream, this means that under ordinary circumstances for a power        plant the temperature drop in the flue gas across the air heat        exchanger can only equal 80% of the temperature gain in the        combustion air stream. By reducing the moisture content of the        coal and consequently the flue gas produced via combustion of        that coal product in the furnace in accordance with this        invention, however, the mass flow rate and specific heat values        for the flue gas stream 306 will be reduced, while pre-heating        of primary air stream 366 and secondary air stream 368 via fan        room coils 364 and 370 will increase the mass flow rate for the        combustion air stream. This will cause the X ratio to increase        towards 100%, thereby greatly enhancing the boiler efficiency of        the power plant operation. Moreover, careful design of the dryer        system in accordance with the principles of this invention can        further enhance the X ratio value to approximately 112%, thereby        rendering the boiler operation even more efficient for producing        electricity. Furthermore, this greatly enhanced X ratio for the        air heat exchanger and boiler efficiency has been achieved        through the use of available waste heat sources within the power        plant operation, which enables improvement of the economics for        the power plant operation on a synergistic basis.

It is important to appreciate that other variations can be made to thefluidized bed dryer arrangements show in FIGS. 31-33. For example, otherwaste heat streams available within the electric power plant like thespent process steam coming off the turbines could be used insubstitution for the hot flue gas or hot condenser cooling waterstreams. Moreover, separate mixing boxes could be inserted within thelines used to deliver the fluidizing air to the first and second stagesof the fluidized bed in order to permit separate adjustment and controlof the temperature of each fluidizing stream. Furthermore, a bi-sectoror external air heater could be employed with both the primary andsecondary airstreams passed through the one side to be heated by the hotflue gas traveling through the other side. If needed, a steam-airpre-heater (“SAH”) can be placed in the hot primary air stream tofurther increase its temperature before it reaches the mixing boxes. Theheat input for this SAH could be provided by steam extracted from thesteam turbine cycle or from other waste heat sources available withinthe plant. Still another variation would be to place a low-temperatureeconomizer heat exchanger in the path of the flue gas after it exits theexternal air pre-heater in order to heat a circulating fluid thatprovides further heat enhancement to the primary and/or secondary airstreams before they reach the external air heater, as shown in FIG. 33.Such a heat exchanger could also be placed before the external airpreheater.

FIG. 32 shows a slightly different integration of the fluidized beddryer 302 into electric power plant 300, compared with FIG. 31 in whichlike elements have been given the same numbers for ease ofunderstanding. Hot condenser cooling water 304 is still used to heatglycol heater 360 for preliminary fan room coil 364 and primary fan roomcoil 370, which, in turn, collectively preheat primary air stream 366and secondary air stream 368 before they are further heated in externalair heater 376 by flue gas 306 to create hot secondary air 382 and hotprimary air 380. The cold primary air stream 366 a is also stilldirected through mixing box 378 to control the temperature of thefluidizing air directed through the bottoms of first stage 350 andsecond stage 352 of the fluidized bed dryer. However, circulating liquidmedium 388 heated in heat exchanger 386 is used as the heating mediumfor both in-bed heat exchanger 354 in first stage 350 and in-bed heatexchanger 356 in second stage 352. Unlike the arrangement shown in FIG.31, hot condenser cooling water 304 is not used as the heating mediumfor in-bed heat exchanger 354 in the first stage 350. This FIG. 32embodiment allows higher temperature heat to be directed to both heatexchangers in fluidized-bed dryer 302 and enhances the flexibility ofthe overall drying system.

FIG. 33 shows a still slightly different arrangement for the fluidizedbed dryer 302 and electric power plant 300. Like FIG. 32, a commonsource of waste heat is used for both in-bed heat exchangers containedin the first stage 350 and second stage 352 of the fluidized-bed dryer302. However, unlike FIG. 32 where the hot primary air 380 exiting theexternal air heater 376 is used to heat the heat exchanger circulatingliquid 388, in FIG. 33 this circulating liquid 388 is heated insideexternal heat exchanger 400 by means of the flue gas stream 402 exitingthe external air pre-heater 376. In this manner, the circulating liquid388 can be heated to approximately 200-300° F. for use in the in-bedheat exchangers 354 and 356. Moreover, this FIG. 33 embodiment providesadditional advantages, because it enables further productive use of theheat content of the flue gas stream, and provides even greaterflexibility to the dryer system design which renders it more efficientin producing the same or better drying performance compared with theembodiments shown in FIGS. 31 and 32.

Still another possible and preferred embodiment of the low-temperature,open-air process utilizing waste heat sources of the present inventionis depicted in FIG. 34. Like elements from FIGS. 31-33 are shown in FIG.34 with the same numbering used previously for ease of understanding ofthe reader.

Instead of a single initial fanroom coil 364 heated by glycol heater360, as shown in FIGS. 31-33, the FIG. 34 embodiment contains separateheat exchangers 530 and 532 that are used initially to preheat primaryand secondary airstreams 366 and 368. Glycol loop 362 heated by means ofhot condenser cooling water slip stream 304 a circulates through heatexchangers 530 and 532 to increase the temperature of the twoairstreams. Such a glycol preheating loop is particularly helpful whenthe low-temperature process system is operated in a cold weatherenvironment.

The primary fanroom coil 370 of FIGS. 31-33 is divided into separateheat exchangers 534 and 536 in the FIG. 34 embodiment. This arrangementpermits greater individual control of the temperature increase providedto primary airstream 366 and secondary airstream 368. Primary airstream366 and secondary airstream 368 exit heat exchangers 534 and 536 atapproximately 100° F. Hot condenser cooling water 304 provides a heatsource to heat exchanger 536, while hot condenser cooling water slipstream 304 a provides a heat source to heat exchanger 534. Hot condensercooling water streams 304 and 304 a combine into stream 358 for returnto cooling tower 346 that produces cold cooling water 342 used to coolspent turbine steam 338 in steam condenser 340.

Like the FIGS. 31-33 embodiments, primary aistream 366 and secondaryairstream 368 are heated by means, of tri-sector air preheater 376before they are directed as airstreams 380 and 382 to the coal mill 324and furnace 330, respectively. Flue gas 306 is directed to APH 376, sothat its valuable waste heat content may be utilized before it is sentto the plant's environmental scrubbers. APH 376 increases thetemperature of primary airstream 380 and secondary airstream 382 fromapproximately 100° F. to approximately 660-690° F. The temperature offlue gas 306 used to heat APH 376 drops from approximately 800-830° F.to approximately 265-277° F.

Cold primary airstream 366 a is diverted from primary airstream 366upstream of APH 376 to provide the fluidizing airstreams 382 for thefirst stage 350 and second stage 352 of fluidized bed dryer 302. Suchcold PA 366 a is typically at 145-150° F. However, it may be heated bymeans of heat exchanger 540 to increase its temperature in a regulatedmanner. The heat source for heat exchanger 540 is provided by means ofheat transfer loop 542, which circulates through heat exchanger 540 andheat exchanger 544. Heat exchanger 544, in turn, is heated by means ofheat transfer loop 546, which draws its heat source from flue gassubstream 306 a in heat exchanger 548. Flue gas substream 306 a exitingheat exchanger 548 is combined with flue gas stream 306 exiting APH 376and passed onto the environmental scrubber equipment before it is ventedto the environment.

The thermal content of heat transfer loop 542 is also directed as stream550 to inbed heat exchangers 354 and 356 contained within fluidizing bed302 for drying the coal. Stream 550 exiting the inbed heat exchangers354 and 356 is reunited with heat transfer loop 542 (bypassing heatexchanger 540 in view of its reduced thermal content), whereupon it isheated once again by means of flue gas 306 in heat exchanger 544 beforebeing directed once again to cold PA 366 a heat exchanger 540 and inbedheat exchangers 354 and 356. In this manner, hot condenser cooling water344 and hot flue gas 306 are utilized in combination to heat theairstream 382 that fluidizes the coal passing through dryer 302, andprovides heating sources for the inbed heat exchangers 354 and 356 thatdry the coal. In this manner, the multiple heat exchangers 360, 530,532, 534, 536, 540, 544, and 548 contained within the system enablegreater regulation of use of the waste heat sources to dry the coal, andmaximize the system's flexibility for various types of coal and processcycles. Bypass line 552 enables a portion of the thermal fluid containedwithin heat transfer loop 542 to bypass heat exchanger 540 to achievegreater control of the temperature of the heat transfer loop.

Hot PA air substream 380 a is diverted from hot PA air stream 380 fortransfer to mixing boxes 556 and 558. Cold PA airstream 382 that hasbeen thermally modified inside heat exchanger 540 is combined with hotPA sub airstream 380 a to regulate the temperature of the fluidizingairstreams provided to the first stage 350 and second stage 352 of dryer302. Separate mixing boxes 556 and 558 permit fluidizing airstreams withdifferent temperatures to be directed to the two dryer stages for moreefficient drying of the coal.

FIG. 35 shows yet another possible embodiment of the low-temperature,open air process of the present invention. It is similar to theembodiment depicted in FIG. 34, with a couple of important exceptions.Like numbers have been used for the same components found in FIGS. 34and 35.

Heat exchanger 540 used to increase the temperature of cold PA 366 a isheated directly by hot flue gas 306 within the FIG. 35 embodiment. Heattransfer loop 546 has connected to it another heat transfer loop 560,which directly conveys that thermal heat content provided to heatexchanger 548 by flue gas 306. The heating fluid 560 that exits heatexchanger 540 is reunited with heat transfer loop 546 at valve 562.Piping 566 between valves 562 and 564 enables heat transfer loop 546 tobe isolated from heat transfer loop 560. Direct transfer of the thermalcontent of flue gas 306 to heat exchanger 540 permits a greatertemperature increase in cold PA 366 a, compared with the FIG. 34embodiment where heat exchanger 540 is heated indirectly by flue gas 306via outer heat transfer loop 542.

Like the FIG. 34 embodiment, the thermal content contained within heattransfer loop 542 of the FIG. 35 embodiment is transported to inbed heatexchangers 354 and 356 of dryer 302 via stream 550. However, instead ofimmediately returning spent stream 550 from the inbed heat exchangers toheat transfer loop 542 at valve 543 (see FIG. 34), the spent thermalstream 550 is diverted in the FIG. 35 embodiment as stream 570 to heatexchanger 572 contained within feed hopper 303. In this manner, stream570 is used to preheat the coal 12 before the coal passes into the firststage 350 of dryer 302 in which it is further preheated and partiallydried. Stream 570 leaves heat exchanger 572, whereupon it is reunitedwith heat transfer loop 542. This preheater may be useful for processingcoal in winter months, when ambient temperatures are colder. It may alsobe useful for operation of the low-temperature processing system of thepresent invention in countries like Australia where coal naturallycontains higher moisture levels. The preheater can also providesignificantly increased efficiencies to the thermal processing of otherparticulate materials like refuse-derived fuels, biomass, etc.

Another feature of the process embodiment set forth in FIG. 35 is coalcooler 574. It may constitute a stand-alone unit as shown in FIG. 35, orelse a third stage of dryer 302 at its exit end. In this case of such acoal cooler integrated into the fluidized bed dryer, the dried coalexits the second stage 352 over a weir into coal cooler stage section574.

As illustrated schematically in FIG. 36, stand-alone coal cooler 574constitutes a vessel 576, having a coal inlet port 578 and a coaldischarge port 580. Located within vessel 576 is distributor plate 582,which comprises a metal plate having a plurality of holes bored throughit—much like the distributor plates employed within the first and secondstages of the fluidized bed dryer 302. Fluidizing air 584 may bepreheated by means of heating coil 586, whereupon it passes underpressure into the plenum region 588 of vessel 576 below distributionplate 582.

Coal 12 dried in the second stage 352 of dryer 302 at approximately 28%moisture and 139° F. is transported through inlet port 578 and collectsinside vessel 576 to form fluidized bed 590. Airstream 584 atapproximately 100° F. and a humidity ratio of approximately 0.0210 isforced through the holes in distributor plate 582 to fluidize the coal590. In doing so, the fluidizing air reduces the temperature of thecoal, and takes on a small portion of its moisture, thereby slightlydrying it further. The coal is discharged from vessel 576 at outlet 580to produce cooled coal 592 at approximately 27% moisture and 117° F. Bycooling the coal, the chances of it spontaneously combusting in storagebefore it is fed to the furnace are significantly reduced. Unlike priorart systems, inert gases need not be introduced into contact with thedried coal to prevent its spontaneous combustion.

Fluidization of the coal in coal cooler 574 produces particulate fines594, which are vented at outlet 596 and conveyed to baghouse 321, wherethey can be collected before the airstream is passed through stack 323to the atmosphere. This dirty air 594 (pre-baghouse treatment) ischaracterized by approximately 69° F. and a 0.0557 humidity ratio.

Portions of a coal cooler 574 that is integrally attached to thedischarge end of a fluidized bed dryer 302 as a third stage are depictedin FIG. 37. FIG. 37 a shows the weir 595, which is adjustably suspendedby means of chains 596 to divide cooler stage 574 from dryer secondstage 352 and define the height of the fluidized coal bed inside thesecond stage as it passes over the top of the weir 595 into the coolerstage.

FIG. 37 b depicts the discharge end 597 of cooler 574 with severaloutlet flip gates 598. These gates press against a gasket 599surrounding the perimeter of the outlet port in the discharge end 597 ofthe dryer when closed to maintain the fluidization condition within thecooler. Pneumatic valves 581 are operatively connected to flip gates 598to open them about shaft 583 to discharge the cooled coal containedwithin cooler 574. The flip gates may be opened in response to a manualinput from an operator when the cooler is full of coal, or else inresponse to a timer signal. In this manner, the coal continuously driedin fluidized bed dryer 302 likewise may be cooled in cooler 574 on acontinuous basis to produce the dried coal ready for transport to thefurnace 330 or storage without spontaneously combusting.

Thus, the coal cooler 374 of the present invention may constitute anintegrated or stand-alone fluidizing stage of the dryer, but without aninbed heat exchanger. The fluidizing air is used to cool the coal to atemperature condition preferably below 120° F. and slightly dry itfurther. If a higher degree of temperature reduction is required thanwhat can be supplied by the fluidizing air, alone, then an inbed heatexchanger could be positioned inside coal cooler 374. However, a coolantfluid like cold water or glycol would be passed through the inbed heatexchanger to enable it to produce a temperature condition below the coaltemperature to cool it.

Returning to the electric power plant environment associated with thecoal drying process and dryer discussed above, use of the hot flue gas27 and hot steam 71 extracted from the steam turbines has previouslybeen discussed in FIG. 2 for improving the efficiency of the electricpower plant 65. However, other alternative arrangements are alsopossible. In FIG. 38, for example, another embodiment of aclosed-cooling circuit with a tri-sector rotating regenerative airpre-heater 76 is shown. In this case, instead of diverting spent steam71 from the steam turbines to act as a heat source for the heatexchanger 70 for preheating primary air stream 20 and secondary airstream 30 before they reach the air heater 76 (see FIG. 2), a portion ofthe hot condenser cooling water 55 in FIG. 38 is routed to the heat coilin heat exchanger 70 for this purpose.

Meanwhile, FIG. 39 shows an alternative embodiment of the FIG. 38arrangement in which hot condenser cooling water 54 is used to heat theheat exchanger 70. In this case, however, a bi-sector rotatingregenerative air pre-heater 420 is used to further heat the primary andsecondary air streams after they exit preliminary heat exchanger 70. Asingle air stream 418 is routed through the one side of bi-sector airpre-heater 420, and the hot flue gas 27 is directed through the otherside to provide the heating medium. The further heated air stream 422splits downstream of the air pre-heater 420 into separate primary airstream 424 and secondary air stream 426. Primary air stream 424 is sentto coal mill 18 to provide positive pressure for the pulverized coaltransported to furnace 25, pre-heating the pulverized coal in theprocess. Secondary air 426 is routed to the wind box 428 off furnace 25whereafter it enters the furnace 25 to promote combustion of the coalinside the furnace.

An open-cooling circuit with a tri-sector rotating regenerative airpre-heater 76 is illustrated in FIG. 40. The coal-fired power plantarrangement is similar to the one depicted in FIG. 38 in which hotcondenser cooling water is used to heat preliminary heat exchanger 70.However, in this case condenser 50 is cooled by an open-cooling circuit,instead of cooling tower 56. Moreover, an in-condenser heat exchanger440 is used to utilize waste heat for the inlet preheating. The separateheat exchanger 440 is placed within the shell of steam condenser 50above the condenser tubes located therein (not shown). This designprovides hot circulating water 442 that is somewhat higher intemperature than the hot condenser cooling water 54 that normally leavesstream condenser 50, and is of much higher water purity.

The hot circulating water 442 leaving in-condenser heat exchanger 440 ispumped to the air-to-water preliminary heat exchanger 70 to preheatprimary air stream 20 and secondary air stream 30 before they reachtri-sector air pre-heater 76. After giving up its sensible heat withinthe heating coil of heat exchanger 70, the cooler cold circulating water444 flows back to in-condenser heat exchanger 440, where it is reheatedby the incoming spent turbine stream.

In an open system, cold cooling water from a lake or river 446 is usedto condense the spent turbine steam in a steam condenser 50. Heattransferred from the steam to the cold cooling water 446 exits steamcondenser 50 as hot cooling water 448 and is typically discharged intothe same lake or river.

In case an inlet air preheat temperature is needed that is higher thanthe one that could be achieved by the in-condenser heat exchanger 440,an auxiliary heat exchanger 450 could be added to increase the airpreheat temperature, as illustrated in FIG. 41. A portion 452 of fluegas 27 leaving the tri-sector air pre-heater 76 is diverted to theauxiliary heat exchanger 450 to increase the temperature of the hotcirculating water 442 leaving the in-condenser heat exchanger 440. Thishotter circulating water 454 then provides sensible heat to the heatingcoil of preliminary air heat exchanger 70. The cooled flue gas stream456 leaving the auxiliary heat exchanger 450 combines with the main fluegas stream 27 that has left air heater 76.

Of course, the bi-sector air pre-heater depicted in FIG. 39 could besubstituted for the tri-sector air pre-heater 76 shown in FIGS. 40-41.Many other air pre-heater arrangements are possible, and could, by wayof example, include a tubular air pre-heater where the combined primaryand secondary air streams 20, 30 flow through the same air pre-heater ofa tubular design, and a combination of tubular and rotating airpre-heaters where the primary air stream 20 is heated in a tubular airpre-heater, while the secondary air stream 30 is heated in abi-sector-rotating air pre-heater. Also, a plate heat exchanger designavailable in the industry could be used instead of a tubular airpre-heater design. Implementation of the inlet air preheat coil would besimilar to that described above.

Another type of coal bed dryer for purposes of this invention is asingle-vessel, single-stage, fixed-bed dryer with a direct or indirectheat source. One embodiment of such a dryer with a direct heat source isillustrated in FIG. 42, although many other arrangements are possible. Afixed-bed dryer is a good choice for drying coal that will be sold toother power plants or other industrial plants. This is because of thelow drying rates and the fact that much longer residence times areneeded for fixed-bed dryers, compared with fluidized-bed dryers, to drya required quantity of coal to a desired degree of moisture reduction.Furthermore, there usually are practical limitations on the use of afluidized bed dryer in a non-plant situation, such as in the miningfield. Under these circumstances, premium waste heat sources, such asthe hot condenser cooling water or compressor heat, may not be availablefor the drying operation. Also, it may be more difficult to cheaplyprovide the necessary quantity of fluidizing air required for afluidized bed.

With the arrangement shown in FIG. 42, the fixed-bed dryer 180 has twoconcentric walls, wherein, a generally cylindrical outer wall 182 and agenerally cylindrical inner wall 184 that define a spatial ring 186between the outer wall 182 and inner wall 184 for air flow. A conicalstructure 188 having a base diameter smaller than the diameter of theinner wall 184, is positioned at the bottom of the fixed-bed dryer 180,axially aligned with the inner wall 184, to create a ring-shaped floordischarge port 190 for discharge of the dried coal 192.

Coal (typically, but not exclusively, wet sized coal 12) enters thefixed bed 180 at the open top 194. The wet sized coal 12 is drawn bygravity to the bottom of the bed dryer 180. A fluidizing air stream 196is generated by a fan 198 drawing cold drying air 200 through anair-to-water heat exchanger 202. The fluidizing air 200 is heated bymeans of waste heat, shown in FIG. 42 as hot condenser cooling water 204drawn from a steam condenser (not shown). As with all of the embodimentsdescribed in this application, other waste heat sources are possible forpractice of the invention.

The fluidizing air 200 enters the bottom of the fixed bed 180 throughboth the conical structure 188 and the spatial ring 186 formed betweeninner wall 184 and outer wall 182. Both the conical structure 188 andthe inner wall 184 are perforated or otherwise suitably equipped toallow fluidizing air 196 to flow through the wet sized coal 12 containedwithin the inner wall 184 of the fixed bed dryer 180, as shown in FIG.42. The fluidizing air 196 escapes into the atmosphere through the opentop 194 of the fixed bed dryer 180.

The fixed bed dryer 180 includes in-bed heat coils 206. Heat for thein-bed heat transfer coils 206 is provided by waste heat, in this case,hot condenser cooling water 204. Waste heat from other sources or steamextracted from the steam turbine cycle, or any combination thereof,could also be used solely or in combination with the condenser wasteheat 204. As wet sized coal 12 is heated and aerated in fixed bed dryer180, dried coal 192 is drawn by gravity or other commercially availablemechanical means to the bottom of the dryer where it is dischargedthrough the discharge ring 190 formed at the bottom of the fixed beddryer 180.

Many advantages are obtained using the present system. The processallows waste heat to be derived from many sources including hotcondenser circulating water, hot flue gas, process extraction steam, andany other heat source that may be available in the wide range ofacceptable temperatures for use in the drying process. The process isable to make better use of the hot condenser circulating water wasteheat by heating the fan room (APH) by 50 to 100° F. at little cost,thereby reducing sensible heat loss and extracting the heat from theoutlet primary and secondary air streams 20, 30 exiting the airpre-heater. This heat could also be extracted directly from the flue gasby use of the air preheat exchanger. This results in a significantreduction in the dryer air flow to coal flow ratio and size of the dryerrequired.

The dryer can be designed to make use of existing fans to supply the airrequired for the fluidized bed by adjusting bed differentials and dustcollector fan capabilities. The beds may utilize dust collectors ofvarious arrangements, some as described herein. The disclosedembodiments obtain primary air savings because one effect of drier coalis that less coal is required to heat the boiler, and thus fewer millsare required to grind coal and less air flow is required to the mills tosupply air to the dryer.

By integrating the dryer into the coal handling system just upstream ofthe bunkers, the boiler system will benefit from the increase in coalfeed temperature into the mills, since the coal exits the dryer at anelevated temperature. The changes to flue gas temperature, residencetime in the bed dryer, flue gas water content, and higher scrubbingrates are expected to significantly affect mercury emissions from theplant.

An advantage of pre-heating the inlet air to the APH is to increase thetemperature of the heat transfer surfaces in the cold, end of the APH.Higher surface temperatures will result in lower acid deposition ratesand, consequently, lower plugging and corrosion rates. This will have apositive effect on fan power, unit capacity, and unit performance. Usingwaste heat from the condenser to preheat inlet air to the APH instead ofthe steam extracted from the steam turbine will result in an increase inthe turbine and unit power output and improvement in cycle and unitperformance. Increasing the temperature of air at the APH inlet willresult in a reduction in APH air leakage rate. This is because of thedecrease in air density. A decrease in APH air leakage rate will have apositive effect on the forced draft and induced draft fan power, whichwill result in a reduction in station service usage, increase in netunit power output, and an improvement in unit performance. For powerplants with cooling towers, the use of waste heat to preheat inlet airto the APH will reduce cooling tower thermal duty and result in adecrease in cooling tower water usage.

Coal drying using the disclosed process will lower water losses in theboiler system, resulting in higher boiler efficiency. Lower sensible gaslosses in the boiler system results in higher boiler efficiency.Moreover, reduced flue gas volumes will enable lower emissions of carbondioxide, oxides of sulfur, mercury, particulate, and oxides of nitrogenon a per megawatt (MW) basis. There is also lower coal conduit erosion(e.g., erosion in conduit pipe caused by coal, particulates, and air),lower pulverization maintenance, lower auxiliary power required tooperate equipment resulting in higher unit capacity, lower ash andscrubber sludge volumes, lower water usage by the plant (waterpreviously tapped from the steam turbine cycle is unaffected), lower airpre-heater cold end fouling and corrosion, lower flue gas duct erosion,and an increase in the percentage of flue gas scrubbed. The bed dryerscan also be equipped with scrubbers—devices that remove contaminates,providing pre-burning treatment of the coal. There is an infinite arrayof temperature levels and design configurations that may be utilizedwith the present invention to treat other feedstock and fuel as well.

The combination of the APH—hot condenser cooling water arrangementpermits a smaller, more efficient bed for drying coal. Present systemsthat utilize process heat from the steam turbine cycle require a muchlarger bed. There is material separation in the current invention. Thisallows for reduced emissions of contaminants like SO₂ and mercury. Thepresent arrangement can be used with either a static (fluidized) beddrier or a fixed bed drier. In a two-stage dryer, the relative velocitydifferential between the first and second stages can be adjusted. Therecan be various temperature gradients, and flexibility in heat ranges inthe various stages to maximize desired results. In a multiple-stagefluidized bed arrangement, there is separation of non-fluidizedmaterial. In the first stage, which in one embodiment represents 20% ofthe dryer distribution surface area more of the air flow, mercury, andsulfur concentrations are pulled out. Because the two-stage bed dryercan be a smaller system, there is less fan power required, which savestremendously on electricity expenses. A significant economic factor indrying coal is required fan horsepower.

From a system standpoint, there is less wear and tear and maintenance ofcoal handling conveyors and crushers, a decrease in the amount of ash,and reduced erosion. It is easier to pulverize coal, so there is morecomplete drying in the mill, less mill power, less primary air required,and lower primary air velocities. Station service power (i.e., auxiliarypower) needs will decrease, plant capacity can be increased, andscrubbers and emissions will improve.

The flow rate of flue gas 306 leaving the furnace 330 firing dried,pulverized coal 326 is lower compared to wet pulverized coal. Also, thespecific heat of the flue gas 306 is lower due to the lower moisturecontent in the dried, pulverized coal 326. The result is reduced thermalenergy of the flue gas 306 and the need for smaller environmentaltreatment equipment. Lower flow rates of the flue gas 306 also result inlower rates of convective heat transfer. Therefore, despite the increasein FEGT with drier fuel, less heat will be transferred to the workingfluid (water or steam, not shown) in the boiler 334. For boilers withfixed heat transfer geometry, the temperature of the hot reheat steam(recycled circulating process steam) may be lower compared to operationwith a wetter fuel. Some decrease in the hot reheat steam temperaturecould be corrected by increasing the surface area of a re-heater (notshown) or changing boiler operating conditions, such as raising burnertilts (the angle at which heat is applied to the boiler) or operatingwith a higher level of excess air. A new boiler could be designed forreduced flow rate of flue gas 306 through the convection pass (the exitpath of the flue gas through the furnace) to achieve desired steamtemperature with normal operating conditions. This should further reducesize and construction costs.

By burning drier coal, station service power will decrease due to adecrease in forced draft (FD), induced draft (ID) and primary air (PA)fan powers and a decrease in mill power. The combination of lower coalflow rate, lower air flow requirements and lower flue gas flow ratecaused by firing drier coal will result in an improvement in boilersystem efficiency and unit heat rate, primarily due to the lower stackloss and lower mill and fan power. This performance improvement willallow plant capacity to be increased with existing equipment.Performance of the back-end environmental control systems typically usedin coal burning energy plants (scrubbers, electrostatic precipitators,and mercury capture devices) will improve with drier coal due to thelower flue gas flow rate and increased residence time.

Burning drier coal also has a positive effect on reducing undesirableemissions. The reduction in required coal flow rate will directlytranslate into reductions in mass emissions of NO_(x), CO₂, SO₂, andparticulates. Primary air also affects NO_(x). With drier coal, the flowrate of primary air will be lower compared to the wet coal. This willresult in a reduced NO_(x) emission rate.

For power plant units equipped with wet scrubbers, mercury emissionsresulting from firing drier coal may be reduced due to reduced airpre-heater gas outlet temperature, which favors the formation of HgO andHgCl₂ at the expense of elemental mercury. These oxidized forms ofmercury are water-soluble and can, therefore, be removed by a scrubber.In addition, flue gas moisture inhibits mercury oxidation towater-soluble forms. Reducing fuel moisture would result in lower fluegas moisture content, which will promote mercury oxidation towater-soluble forms. Therefore, with drier coal, mercury emissions arelower compared to usage of wetter coals.

Advantages of lower moisture content in the coal as it travels throughthis limited portion of the system include: drier coal is easier topulverize, and less mill power is needed to achieve the same grind size(coal fineness); increased mill exit temperature (the temperature of thecoal and primary air mixture at mill exit); and better conveying (lessplugging) of coal in coal pipes which convey the coal to the furnace 25.Additionally, less primary air stream 20 will be needed for coal dryingand conveying. Lower primary air velocities have a significant positiveimpact on erosion in coal mill 324, coal pipes, burners and associatedequipment, which reduces coal pipe and mill maintenance costs, whichare, for lignite-fired plants, very high.

With drier coal, the flame temperature in the furnace 330 is higher dueto lower moisture evaporation loss and the heat transfer processes isimproved. The higher flame temperature results in larger radiation heatflux to the walls of furnace 330. Since the moisture content of theexiting flue gas 306 is reduced, radiation properties of the flame arechanged, which also affects radiation flux to the walls of furnace 330.With higher flame temperature, the temperature of coal ash particlesexiting the furnace 330, is higher, which could increase furnace foulingand slagging. Deposition of slag on furnace walls reduces heat transferand results in a higher flue gas temperature at the furnace exit. Due toa reduction in coal flow rate as fuel moisture is reduced, the amount ofash entering the boiler will also be reduced. This reduces solidparticle erosion in the boiler 32 and maintenance requirements for theboiler 32 (e.g., removal of the soot that collects on the interiorsurface of the boiler).

The flow rate of flue gas 306 leaving the furnace 330 firing dried,pulverized coal 326 is lower compared to wet pulverized coal. Lower fluegas rates generally permit decreased size of environmental controlequipment and fans. Also, the specific heat of the flue gas 306 is lowerdue to the lower moisture content in the dried, pulverized coal 326. Theresult is reduced thermal energy of the flue gas 306. Lower flow ratesof the flue gas 306 also results in lower rates of convective heattransfer. Therefore, despite the increase in FEGT with drier fuel, lessheat will be transferred to the working fluid (water or steam) in theboiler system convective pass.

For economic reasons, complete drying of the coal is not needed, nor isit recommended, as removing a fraction of the total fuel moisture issufficient. The optimal fraction of removed moisture depends on thesite-specific conditions, such as coal type and its characteristics,boiler design, and commercial arrangements (for example, sale of driedfuel to other power stations). Waste process heat is preferably, but notexclusively used for heat and/or fluidization (drying, fluidization air208) for use in an in-bed heat exchanger. As has been shown, this heatcan be supplied directly or indirectly in one or more stages.

It has been found surprisingly that the concentration of sulfur andmercury contaminants contained within the segregation stream streams260, 268, and 270 are significantly greater than that of wet coal feedstream 12. Likewise, the elutriated fines stream 166 exiting the top ofthe fluidized-bed dryer is enhanced in the presence of contaminants likefly ash, sulfur, and mercury. By using the particle segregation methodof the present invention, the mercury concentration of the coal productstream 168 can be reduced by approximately 27%, compared with themercury concentration of the wet coal feed stream 12. Moreover, thesulfur concentration of the coal product stream 168 can be reduced byapproximately 46%, and the ash concentration can be reduced by 59%.Stated differently, using the present invention, approximately 27-54% ofthe mercury appearing in the wet coal feed can be concentrated in thesegregation stream and elutriated fines output streams, and thereforeremoved from the coal product stream that will go to the boiler furnace.For sulfur and ash, the corresponding values are 25-51% and 23-43%,respectively. By concentrating the contaminants within the segregationstream in this manner, and significantly reducing the presence of thecontaminants in the coal product stream 168 going to the boiler furnacefor combustion, there will be less mercury, SO₂ and ash contained withinthe resulting flue gas, and therefore less burden on the scrubbertechnology conventionally used within industrial plant operations totreat the flue gas stream before it is vented to the atmosphere. Thiscan result in significant operational and capital equipment cost savingsfor a typical industrial plant operation.

The fluidized bed designs for this invention are intended to be customdesigned to maximize use of waste heat streams available from a varietyof power plant processes without exposing the coal to temperaturesgreater than 300° F., preferably between 200-300° F. Other feedstock orfuel temperature gradients and fluid flows will vary, depending upon theintended goal to be achieved, properties of the fuel or feedstock andother factors relevant to the desired result. Above 300° F., typicallycloser to 400° F., oxidation occurs and volatiles are driven out of thecoal, thereby producing another stream containing undesirableconstituents that need to be managed, and other potential problems forthe plant operations.

The fluidized-bed dryers are able to handle higher-temperature wasteheat sources by tempering the air input to the dryer to less than 300°F. and inputting this heat into heat exchanger coils within the bed. Themulti-stage design of a fluidized-bed dryer creates temperature zoneswhich can be used to achieve more efficient heat transfer by counterflowing of the heating medium. The coal outlet temperature from a dryerbed of the present invention is relatively low (typically less than 140°F.) and produces a product which is relatively easy to store and handle.If a particular particulate material requires a lower or higher producttemperature, the dryers can be designed to provide the reduced orincreased temperature.

Elutriated particles 600 collected by particle-control equipment aretypically very small in size and rich in fly ash, sulfur, and mercury.FIG. 19 is a schematic drawing indicating a process for removing mercurythrough the use of activated steam 602 to produce activated carbon 604.As shown in FIG. 19, elutriated particle stream 600 is heated in afluidized-bed heater or mild gasifier 606 to a temperature of 400° F. orhigher to evaporate the mercury. Fluidizing air 608, forced through thefluidized bed 608, drives out the mercury into overhead stream 610.Evaporated mercury in overhead stream 610 can be removed by existingcommercially available mercury control techniques, for example, byactivated carbon injected into the air stream, or the mercury-laden airstream 610 may be passed though a bed of activated carbon 612 asillustrated in FIG. 19. Since mercury concentration in the treatmentstream 610 will be much higher compared to the flue gas 306 leaving thefurnace 330, and the total volume of the air stream that needs to betreated is very small compared to the flue gas leaving the furnace, thiswill be a very efficient mercury removal process. A heat exchanger 614through which cooling fluid 616 is circulated, may be used to cool hotmercury-free stream 618. Heat can be harvested in the cooling processand used to preheat fluidization air 620 to the fluidized bed heater ormild gasifier 606. The mercury-free fines 622 can be burned in thefurnace 330 or, as illustrated in FIG. 19, can be activated by steam 602to produce activated carbon 604. The produced activated carbon 604 canbe used for mercury control at the coal-drying site or can be sold toother coal-burning power stations.

FIG. 20 illustrates a process for gasifying elutriated fines 600.Elutriated particle stream 600 is gasified in fluid bed gasifier 700 incombination with fluidizing air 702. A gasifier is typically utilized ata higher temperature, such as 400° F., where combustible gases andvolatiles are driven off. The product gas stream 704 is combusted in acombustion turbine 706 consisting of a combustion chamber 708,compressor 710, gas turbine 712 and generator 714. The remaining char716 in the fluidized-bed gasifier will be mercury-free, and can beburned in the existing furnace 330 or treated by steam 718 to produceactivated carbon 720.

The segregation streams can also be rich in sulfur and mercury. Thesestreams can be removed from the process and land-filled or furtherprocessed in a manner similar to the elutriated fines stream, to removeundesirable impurities.

In a preferred embodiment of the present invention, the segregation coalparticle stream 170 or 260 is conveyed directly to a scrubber assembly600 for further concentration of the contaminants by removal of finecoal particles trapped therein. An embodiment of the scrubber assembly600 of the present invention is shown in a cut-away view in FIGS. 21 aand 21 b. The scrubber assembly 600 is a box-like enclosure having sidewalls 602, an end wall 604, bottom 606, and top 608 (not shown), and isattached to the dryer 250 sidewall to encompass an segregation streamdischarge port 610 through which the screw auger 194 partially extends.It should be noted that any other appropriate device that is capable ofconveying the segregation stream coal particles in a horizontal mannercould be substituted for the screw auger, including a belt, ram, or dragchain.

The screw auger 194 will move the segregation stream particles lyingnear the bottom of the fluidized bed across the bed, through segregationstream discharge part 610, and into scrubber assembly 600 where they canaccumulate separate and apart from the fluidized dryer. Distributorplate 620 is contained within the scrubber assembly 600. A substream ofhot fluidizing air 206 passes upwardly through holes 622 in distributorplate 620 to fluidize the segregation particle stream contained withinthe scrubber assembly. Of course, the segregation stream particles willreside near the bottom of the fluidized bed due to their greaterspecific gravity, but any elutriated fines trapped amongst thesesegregation stream particles will rise to the top of the fluidized bed,and be sucked back into the fluidized dryer bed 250 through inlet hole624 (the heat exchanger coils 280 are shown through this hole in FIG.22). In this manner, the segregation particles stream is furtherprocessed within the scrubber assembly of FIG. 21 to clean out theelutriated fines, thereby leaving an segregation coal particle streamthat has a greater concentration of contaminants, and allowing the fineswhich are lower in contaminants to be returned to the fluidized bed forfurther processing.

When the segregation stream particles contained within the scrubberassembly have accumulated to a sufficient degree, or are otherwiseneeded for another purpose, gate 612 in end wall 604 may be opened toallow the accumulated segregation stream particles to be dischargedthrough an outlet hole in the end wall wherein these segregation streamparticles are pushed by the positive pressure of the imposed by screwauger 294 on the segregation stream particles through them, or by othersuitable mechanical conveyance means. Gate 612 could also be operated bya timer circuit so that it opens on a periodic schedule to discharge theaccumulated segregation particles.

Yet another embodiment 630 of the scrubber assembly is shown in FIGS.22-24, constituting two scrubber subassemblies 632 and 634 for handlinglarger volumes of segregation stream particles produced by thefluidized-bed dryer 250. As can be seen more clearly in FIG. 24, screwauger 194 extends through vestibule 636. Segregation stream coalparticles are conveyed by screw auger 194 to this vestibule 636 and theninto collection chambers 638 and 640 which terminate in gates 642 and644, respectively, or other appropriate type of flow control means.

As discussed above, distributor plates 654 and 656 may be includedinside the collection chambers 638 and 640 (see FIG. 26) so that afluidizing airstream passed through holes 658 and 660 in the distributorplates fluidize the segregation stream particles to separate anyelutriated fines trapped amongst the denser segregation streamparticles. Once gates 642 and 644 are opened, the elutriated fines willrise to the tops of chutes 646 and 648 through holes 660 and 662 forconveyance by suitable mechanical means back to the fluidized bed dryer250. The segregation stream particles will drop through the bottom ofchutes 646 and 648, as previously described.

Once a predetermined volume of segregation stream particles haveaccumulated within the collection chambers 638 and 640, or apredetermined amount of time has elapsed, then gates 642 and 644 areopened to permit the segregation stream particles to be discharged intochutes 646 and 648, respectively. The segregation stream particles willfall by means of gravity through outlet parts 650 and 652 in the bottomof chutes 646 and 648 into some other storage vessel or conveyance meansfor further use, further processing, or disposal.

Gates 642 and 644 may be pivotably coupled to the collection chambers638 and 640, although these gates may also be slidably disposed,upwardly pivoting, downwardly pivoting, laterally pivoting, or any otherappropriate arrangement. Additionally, multiple gates may be operativelyassociated with a collection chamber to increase the speed of dischargeof the segregation stream coal particles therefrom.

In an example embodiment, as illustrated in FIG. 25, gate 642 or 644could include a planar door portion 672 that covers discharge port 632of collection chamber 638, 640. Door portion 672 may have an areagreater than an area of discharge port 632.

Door portion 672 may comprise any rigid material such as steel,aluminum, iron, and like materials with similar physicalcharacteristics. In an alternate embodiment, gate 670 will be repeatedlyoperated, it may be advantageous to use a thinner material, which canreduce its weight. In this embodiment, the door portion 672 may alsoinclude bracing or supports (not shown) to add additional supportagainst any outwardly acting pressure from within collection chamber638, 640.

Gate 670 also includes at least one seal portion 674 disposed on or toan inner surface of door portion 672 to form a generally positive sealover discharge opening 632. Seal portion 674 could have an area greaterthan an area of discharge opening 632. Seal member 674 could compriseany resiliently compressible material such as rubber, an elasticplastic, or like devices having similar physical characteristics.

A cover 676 may be disposed on seal member 672 to protect or cover itfrom the fluidized and non-fluidized material that will confronting sealgate 670. As particularly illustrated in FIG. 26, cover 676 comprises asheet having an area that can be less than an area of discharge opening632. When gate 670 is in its closed position cover 676 is nested indischarge port 632. Cover 676 can comprise any rigid material such assteel, aluminum, iron, and like materials with similar physicalcharacteristics. However, other materials may also be utilized for cover676.

In an example embodiment, an actuation assembly 680 is operativelycoupled to gate 670 to move it from an open position and a closedposition, whereby the coal is dischargeable from fluidizing collector620 when gate 670 is in the open position. Actuation assembly 280comprises a pneumatic piston rod 684 and cylinder 686 that are inoperative communication with a fluid pneumatic system (not shown). Thefluid pneumatic system may include the utilization of fluid heat streamssuch as waste heat streams, primary heat streams, or a combination tothe two.

Since fluidization will be occurring in the fluidizing collector 632,construction materials may be used that are able to withstand thepressures needed to separate the fine particulates from the denserand/or larger contaminated material. Such construction material caninclude steel, aluminum, iron, or an alloy having similar physicalcharacteristics. However, other materials may also be used tomanufacture the fluidizing collection chamber 638, 640.

The fluidizing collection chamber 638, 640 can also, although notnecessary, include an in-collector heater (not shown) that may beoperatively coupled to a fluid heat stream to provide additional heatand drying of the coal. The in-collector heater may be fed by any fluidheat stream available in the power plant including primary heat streams,waste streams, and any combination there.

As illustrated in FIGS. 23 and 24, the top, wall 632 a and 632 b offluidizing collection chamber 638, 640 may traverse away from thefluidized bed at an angle such that the fluid heat stream entering thefluidizing collection chamber 638, 640 is directed toward passage A orsecond passage B, as indicated by reference arrows A and B, and into thefluidized bed. An inner surface of the top wall 632 can includeimpressions, or configurations such as channels, indentations, ridges,or similar arrangements that may facilitate the flow of the fluidizedparticulate matter through passage A or second passage B and into thefluidized bed.

Referring to FIGS. 22 and 27, a window assembly 650 may be disposed onthe peripheral wall 651 to permit viewing of the fluidization occurringwithin the interior of the fluidizing collection chamber 638, 640. In anexample embodiment of the present invention, the window assembly 650comprises at least an inner window 652 comprising a transparent and/orshatter resistant material such as plastic, thermoplastic, and likematerials fastened to and extending across a window opening 654. Asupport or plate 656 may be disposed to a perimeter outer surface of theinner window 652 to provide support against outwardly acting pressureagainst the inner window 652. The support 656 may comprise anysubstantially rigid material such as steel, aluminum, or like material.A second or outer window 658 may be disposed to an outer surface of thesupport 656 to provide additional support against outwardly actingpressures within the fluidizing collection chamber 638, 640. A bracket660 and fastener 662 may be utilized to secure window assembly 650 intoplace. Bracket 660 may comprise an L-shape, C-shape, or similar shapethat is capable of securing the window assembly 650. Fastener 662 maycomprise a bolt, screw, c-clamp, or any fastener known to one skilled inthe art.

Junction 300 comprises a bottom wall 302, a top wall 304 and a pluralityof side walls 306 defining an interior 308. A distributor plate 310 isspaced a distance from the bottom wall 302 of junction 300 defining aplenum 312 for receiving at least one fluid heat stream that flows intothe plenum 312 through at least one inlet 316. Distributor plate 312 ofjunction 300 is preferably sloped or angled toward fluidizing collector220 to assist in the transport of non-fluidized material from thefluidized dryer bed 130. As the non-fluidized material travels throughjunction 300, apertures 314 extending through distributor plate 310 todiffuse a fluid heat stream through the non-fluidized material; therebycausing the separation of fine particulate material. The fineparticulate material becomes fluidized and flows back into the interior106 of fluidized dryer bed 130. The apertures 314 extending throughdistributor plate 310 of junction 300 may be angled during manufacturingto control a direction of the fluid heat stream.

Use of the segregation stream particles separated from the dryer 250 bythe scrubber assembly 600 will depend upon its composition. If thesesegregation stream particles contain acceptable levels of sulfur, ash,mercury, and other undesirable constituents, then they may be conveyedto the furnace boiler for combustion, since they contain desirable heatvalues. If the undesirable constituents contained within thesesegregation stream particles are unacceptably high, however, then thesegregation stream particles may be further processed to remove some orall of the levels of these undesirable constituents, as disclosed morefully in U.S. Ser. Nos. 11/107,152 and 11/107,153, both of which werefiled on Apr. 15, 2005 and share a common co-inventor and co-owner withthis application, and are incorporated hereby. Only if the levels ofundesirable constituents contained within the segregation streamparticles are so high that they cannot be viably reduced through furtherprocessing will the segregation stream particles be disposed of in alandfill, since this wastes the desirable heat values contained withinthe segregation stream particles. Thus, the scrubber assembly 600 of thepresent invention not only allows the segregation stream coal particlesstream to be automatically removed from the fluidized bed to enhance theefficient and continuous operation of the dryer, but also permits thesesegregation stream particles to be further processed and productivelyused within the electricity generation plant or other industrial plantoperation.

The following examples illustrate the low-temperature coal dryingprocess and dryer and scrubber apparati that form a part of the presentinvention.

Example I Effect of Moisture Reduction on Improvement in Heat Volume ofLignite Coal

A coal test burn was conducted at Great River Energy's Coal Creek Unit 2in North Dakota to determine the effect on unit operations. Lignite wasdried for this test by an outdoor stockpile coal drying system. Theresults are shown in FIG. 43.

As can be clearly seen, on average, the coal moisture was reduced by6.1% from 37.5% to 31.4%. These results were in close agreement withtheoretical predictions, as shown in FIG. 43. More importantly, a 6%reduction in moisture content of the lignite coal translated toapproximately a 2.8% improvement in the net unit heat rate of the coalwhen combusted, while an 8% moisture reduction produced approximately a3.6% improvement in net unit heat rate for the lignite coal. Thisdemonstrates that drying the coal does, in fact, increase its heatvalue.

Example II Effect of Moisture Reduction on the Coal Composition

PRB coal and lignite coal samples were subjected to chemical andmoisture analysis to determine their elemental and moisture composition.The results are reported in Table 1 below. As can be seen, the lignitesample of coal exhibited on average 34.03% wt carbon, 10.97% wt oxygen,12.30% wt fly ash, 0.51% wt sulfur, and 38.50% wt moisture. The PRBsubbituminous coal sample meanwhile exhibited on average 49.22% wtcarbon, 10.91% wt oxygen, 5.28% wt fly ash, 0.35% wt sulfur, and 30.00%moisture.

An “ultimate analysis” was conducted using the “as-received” values forthese lignite and PRB coal samples to calculate revised values for theseelemental composition values, assuming 0% moisture and 0% ash (“moistureand ash-free”), and 20% moisture levels, which are also reported inTable 1. As can be seen in Table 1, the chemical compositions andmoisture levels of the coal samples significantly change. Morespecifically for the 20% moisture case, the lignite and PRB coal samplesexhibit large increases in carbon content to 44.27% wt and 56.25% wt,respectively, along with smaller increases in oxygen content to 14.27%wt and 12.47% wt, respectively. The sulfur and fly ash constituentsincrease slightly too (although not on an absolute basis). Just asimportantly, the heat value (HHV) for the lignite coal increased from6,406 BTU/lb to 8,333 BTU/lb, while the HHV value for the PBR coalincreased from 8,348 BTU/lb to 9,541 BTU/lb.

TABLE 1 Moisture & Ash- As-Received Free 20% Fuel Moisture Units LignitePRB Lignite PRB Lignite PRB Carbon % wt 34.03 49.22 69.17 76.05 44.2756.25 Hydrogen % wt 2.97 3.49 6.04 5.39 3.87 3.99 Sulfur % wt 0.51 0.351.04 0.54 0.67 0.40 Oxygen % wt 10.97 10.91 22.29 16.86 14.27 12.47Nitrogen % wt 0.72 0.75 1.46 1.16 0.92 0.86 Moisture % wt 38.50 30.000.00 0.00 20.00 20.00 Ash % wt 12.30 5.28 0.00 0.00 16.00 6.30 TOTAL %wt 100.00 100.00 100.00 100.00 100.00 100.00 HHV BTU/lb 6,406 8,34813,021 12,899 8,333 9,541 H^(T) _(fuel) BTU/lb −2,879 2,807 −1,664−2,217

Example III Effect of Moisture Level on Coal Heat Value

Using the compositional values from Table 1, and assuming a 570 MW powerplant releasing 825° F. flue gas, ultimate analysis calculations wereperformed to predict the HHV heat values for these coal samples atdifferent moisture levels from 5% to 40%. The results are shown in FIG.44. As can be clearly seen, a linear relationship exists between HHVvalue and moisture level with higher HHV values at lower moisturelevels. More specifically, the PRB coal sample produced HHV values of11,300 BTU/lb at 5% moisture, 9,541 BTU/lb at 20% moisture, and only8,400 BTU/lb at 30% moisture. Meanwhile, the lignite coal sampleproduced HHV values of 9,400 BTU/lb at 10% moisture, 8,333 BTU/lb at 20%moisture, and only 6,200 BTU/lb at 40%. This suggests that boilerefficiency can be enhanced by drying the coal prior to its combustion inthe boiler furnace. Moreover, less coal is required to produce the sameamount of heat in the boiler.

Example IV Effect of Coal Moisture Level on Power Plant Efficiency

For purposes of this Example IV, four different dryer systemconfigurations (A, B, C, and D) were used. They are as follows:

Configuration A: Base Case (BC)

The BC option is tightly integrated with the power plant equipment. Itinvolves use of a tri-sector rotating regenerative air pre-heater (APH),a heat exchanger for preheating the primary and secondary air streams, afluidized bed dryer, and a heat exchanger for heating of the heattransfer medium for the in-bed heat exchanger, as shown more fully inFIG. 45. In this arrangement, the APH is used to increase thetemperature level of waste heat.

Waste heat from the steam condenser is used to preheat the primary air(“PA”), secondary air (“SA”), and fluidizing air (“FA”) streams. This isachieved by diverting a small fraction of the hot condenser coolingwater from the rest of the flow and passing it through a water-to-airheat exchanger wherein the PA, SA, and FA streams are preheated to atemperature of approximately 100° F. The cold cooling water is thencirculated back to the tower. This lowers cooling tower duty, andreduces the amount of water required for a cooling tower.

Preheated PA and SA streams flow to the PA and FD fans and the, throughthe primary and secondary air sectors of the APH. The SA stream, heatedin the SA sector of the APH, is delivered to the boiler windbox, whereinit is distributed to the burners. A portion of the PA, called herein the“hot PA,” is extracted downstream of the APH. Temperature of the cold PAstream is in a 140° F. range, while the hot PA temperature is in the750° F. range. The remaining portion of the PA is delivered to the coalpulverizers.

The hot PA stream passes through an air-to-water heat exchanger, whereinit transfers heat to the heat transfer fluid, in this case water. Thehot water is circulated through the in-bed heat exchanger, whichtransfers heat to a fluidized bed. After passing through the heatexchanger, the hot PA stream is in the 200-240° F. range. The FA stream,as the name suggests, fluidizes and dries coal in the fluidized beddryer.

For a dryer of the fixed geometry, i.e., given distributor area, theamount of FA (i.e., the sum of the cold and hot PA flows) is constant.In the BC configuration, the temperature of the FA stream can becontrolled by changing the proportions of the hot PA and cold PAstreams. As the hot PA flow increases, the amount of available heat forthe in-bed heat exchanger increases. This increases the amount of coalmoisture that can be removed from coal in the fluidized bed dryer.Maximum coal drying is achieved when all the FA needed for the dryer isdelivered as the hot PA stream. This operational mode results in themaximum surface temperature of the in-bed heat exchanger tubes and themaximum bed temperature.

As the hot PA flow increases, the amount of the PA and total air flow(PA+SA) through the APH increases. This increase in the air flow throughthe APH results in a decrease in the flue gas temperature leaving theAPH which, in turn, results in a lower stack loss, and an increase inboiler and unit efficiency. Therefore, the performance improvement withthe BC arrangement is higher compared to the case when dried coal isdelivered to the power plant and burned without the on-site drying.

The BC option will, most likely, be used to retrofit existing or designnew power stations burning high-moisture lignite or PRB coals sincethese are, typically, equipped with tri-sector APHs.

Configuration B: High-Temperature (HT) Case

The HT option is less tightly integrated with the power plant equipment,compared to the BC option. As shown more fully in FIG. 46, the FA streamis separate from the PA and SA streams. The HT case involves a bi-sectorAPH, heat exchangers for preheating the PA/SA and FA streams, afluidized-bed dryer (“FBD”) fan, fluidized-bed dryer, and heatexchangers for heating the FA stream and water for the in-bed heatexchanger by using the high-temperature flue gas.

Similar to the BC case, waste heat from the steam condenser is used topreheat the PA+SA and FA streams. This is achieved by diverting a smallfraction of the hot condenser cooling water from the rest of the flowand passing it through a water-to-air heat exchanger wherein the PA+SAand FA streams are preheated to a temperature of approximately 100° F.The cold cooling water is then circulated back to the tower. This lowerscooling tower duty and reduces the amount of water required for acooling tower.

Preheated primary (PA+SA) streams flow through the FD fan and thenthrough the APH wherein they are further heated. The PA stream isseparated from the SA stream, and is delivered to the coal pulverizers.The SA stream is delivered to the boiler windbox, wherein it isdistributed to the burners.

The preheated FA stream is passed through the FGD fan, wherein itspressure is increased to about 40″. The FA stream then passes throughthe air-to-water heat exchanger, wherein its temperature is increased tothe 200-240° F. range. The heated FA stream is then delivered to thefluidized-bed dryer wherein it fluidizes and dries the coal. The waterfor the in-bed heat exchanger is heated in a water-to-water heatexchanger that is placed in a serial arrangement.

The heat for both heat exchangers is extracted from the hot flue gasupstream of the APH, using, in this case, water or other suitable liquidas a heat transfer medium. Other, simpler arrangements are possible. Forexample, the heat transfer medium could be eliminated by combining theabove-mentioned three heat exchangers into one combined heat exchanger.In such an arrangement, the FA stream will be heated in the fluegas-to-FA part of the combined heat exchanger and the water for thein-bed heat exchanger will be heated in the flue gas-to-water part ofthe combined heat exchanger. However, for the purpose of this analysis,the details of the heat exchanger arrangement are not important.

After passing through the heat exchanger, the cooler flue gas flowsthrough the bi-sector APH wherein it is further cooled. As a consequenceof this heat exchanger arrangement, the temperature of the flue gasleaving the APH is lower compared to the case where there is no heatextraction upstream of the APH. However, since the PA+SA streamsentering the APH is preheated by using waste heat from the condenser,the temperature of metal matrix in the cold end of the APH is not toolow to cause increased corrosion and plugging of heat transfer surfacesthat is caused by deposition of sulfuric acid.

Performance improvement that could be achieved by the HT arrangement isanticipated to be less compared to the BC configuration. Results ofpreliminary calculations confirm this. Also, since the FA can be heatedto a temperature similar to the BC configuration, the size of thefluidized bed dryer will be similar to or the same as the BCconfiguration.

The HT configuration will, most likely, be retrofitted at power plantsthat were originally designed for Eastern bituminous (“EB”) coals, butin order to reduce emissions an/or operating costs are not burningPowder River Basin (“PRB”) coals or PRB/EB coal blends.

Configuration C: Low-Temperature (LT) Case

The LT configuration is similar to the HT option. As shown more fully inFIG. 47, the major difference is that the heat for preheating the FAstream is extracted from the flue gas downstream of the APH. The FAstream is separate from the PA and SA streams. The LT configuration alsoinvolves a bi-sector APH, heat exchangers for preheating the PA/SA andFA streams, FBD fan, fluidized-bed dryer, and heat exchangers forheating the FA stream and water for the in-bed heat exchanger by usingthe low-temperature flue gas.

Similar to the BC and HT configurations, waste heat from the steamcondenser is utilized to preheat the PA+SA and FA streams. This isaccomplished by diverting a small fraction of the hot condenser coolingwater from the rest of the flow, and passing it through a water-to-airheat exchanger where the PA+SA and FA streams are preheated to atemperature of approximately 100° F. The cold cooling water is thencirculated back to the cooling tower. This lowers cooling tower duty andreduces the amount of water required for a cooling tower.

Preheated primary (PA+SA) streams flow through the FD fan and thenthrough the APH where they are further heated. PA is separated from theSA and is delivered to the coal pulverizers. The SA stream is deliveredto the boiler windbox, where it is distributed to the burners.

The FA stream, preheated by the waste heat from the steam condenser, ispassed through the FBD fan, where its pressure is increased to about40″. The high-pressure FA stream then passes through the air-to-waterheat exchanger, wherein its temperature is increased to the 250+° F.range. If a source of waste process steam is available, a steam-airheater (SAH) could be used to further increase the temperature of the FAstream, and increase drying capacity of the fluidized bed dryer. Theheated FA stream then passes through the fluidized-bed heat exchangerwherein it heats the water for the in-bed heat exchanger. Cooler FAstream is then delivered to the fluidized bed dryer where it fluidizesand dries the coal.

Since in this case the temperature of the FA stream and hot water forthe in-bed heat exchanger will be lower, compared to the BC and HTconfigurations, this will lower drying capacity of the fluidized beddryer. As a consequence, the fluidized-bed dryer will be larger in size,compared to the BC and HT configurations. This will result in larger FArequirements and higher FBD fan power. Also, the amount of coal moisturethat could be removed in the dryer will be less. Therefore, performanceof the LT configuration will be less compared to the BC and HTconfigurations.

The LT option offers no advantage compared to the HT case. This isbecause the equipment is pretty much the same but is arrangeddifferently, and system performance is lower compared to the BC and HTconfigurations.

A combination of the HT and LT configurations is also possible, whereinheat is extracted from the flue gas upstream and downstream of the APH.This could also be combined with the waste heat utilization form thesteam condenser. Although the combined HT/LT option offers increasedoperational flexibility, the amount of required equipment and capitalcost are significantly increased.

Configuration D: Ultra-Low-Temperature (ULT) Case

In the ULT configurations shown in FIG. 48, the FA stream is separatefrom the PA+SA streams and is heated by using waste heat from thecondenser to a temperature of approximately 100° F. The heat for thein-bed heat exchanger will be supplied directly by circulating the hotcondenser cooling water through the heat exchanger tubes. This willresult in tube surface temperature of approximately 100° F. No wasteheat from the flue gas is used in this case.

Since the temperature of the FA stream and the water for the in-bed heatexchanger will be significantly lower compared to the previouslydescribed Configurations A, B, and C, this will require a very large FBdryer. Also, the drying capacity of the dryer and the amount of coalmoisture that could be removed in the dryer will be significantly lower.However, less equipment will be needed for this option, which willreduce capital cost.

This option could be modified by using waste heat from the condenser topreheat the PA+SA stream into the APH during the winter. This willeliminate the use of process steam to keep the PA+SA stream above thefreezing temperature.

Another possible modification of the ULT case involves use of the SAHthat could be used to increase the temperature of the FA stream andimprove dryer performance.

The effect on boiler efficiency of lignite (825° F. vs. 650° F. fluegas) and PRB (825° F. flue gas) coal dried to different moisture levelsin accordance with the Configuration B dryer system is shown in FIG. 49.Drier coals make the boiler burn more efficiently. In this case, an 8%gain in boiler efficiency was realized.

Application of the four different dryer configurations A, B, C, and D tolignite coal at an 825° F. flue gas temperature is shown in FIG. 50. Thelow-temperature and ultra-low-temperature configurations (C and D)provide the best increases in boiler efficiency.

The impact on flue gas temperature exiting the APH for lignite coalusing the four different configurations, and PRB coal using thehigh-temperature configuration is shown in FIG. 51. The flue gas for allof these options entered the APH at 825° F. The lowest flue gas exittemperature (210° F. for 20% moisture coal) is realized for thelow-temperature configuration (C). This means that the heat contentcontained within the flue gas entering the APH was used moreproductively with this option.

The impact on the flow rate of the flue gas out of the APH (ID faninlet) for the lignite and PRB coals is shown in FIG. 52. Lower flowrates are produced when lower-moisture coal is burned in the boiler.Thus, smaller scrubbers and precipitators will be required to treat theflue gas when drier coals are used. Moreover, lower levels of energywill be used to run the IP fans needed to pump the flue gas.

Also shown in FIG. 52 is the impact on the air flow entering the boilerfor lignite and PRB coals at different moisture levels. At lowermoisture levels, this flow rate will also be reduced. Therefore, smallerfans will be needed, and energy costs can be saved.

The impact on the power requirements for the FD fan used to drive thesecondary air flow is shown in FIG. 53. These power requirements dropslightly at lower moisture levels in the coal, because the air flows aresmaller.

The impact on the power requirements for the ID fans used to drive theflue gas for lignite coal for the four different configurations and PRBcoal is shown in FIG. 54. Much bigger energy savings are realized inthis area. Again, low-temperature Configuration C seems to provide thelargest energy requirement drop. This is very significant, since thepower plant uses four ID fans, thereby multiplying four-fold theseresults.

The impact on coal flow rates for lignite (825° F. vs. 650° F. flue gas)and PRB coal (825° F. flue gas) is shown in FIG. 55. The needed coalflow drops because of the boiler efficiency gains and coal weight lossesdue to the drying process. Therefore, the coal does not need to be fedas quickly to the boiler to produce the necessary heat to run the powerplant.

As shown in FIG. 56, lower mill power is required to run the pulverizersat lower coal moistures. A 20% drop in power requirements is realized.This is significant, since power plants may need 6-8 pulverizers togrind the coal.

The impact on the net unit heat rate for the different dryerconfigurations used to dry the lignite and PRB coals is shown in FIG.57. Net unit heat rate combines the increases in boiler efficiency,turbine efficiency, and reduced station service requirements produced bythe drying systems. This indicates the total energy needed to produceelectrical power. As shown in FIG. 58, the net unit heat rate is reducedfor lower moisture coals. The low-temperature configuration provides thebest results, although the base case is also good.

FIG. 59 shows the impact heat rejected to the cooling tower for thedifferent drying configurations. Because some of the hot condensercooling water has been diverted to heat the fan room coils, less heat islost in the cooling tower. The ultra-low-temperature option provides thebest results with the low-temperature option the next best.

These results collectively demonstrate that use of waste heat sourcesavailable at a power plant in the low-temperature drying process of thepresent invention to dry the coal feed significantly enhances theefficiency of the power plant operation. Improvements in boilerefficiency, net unit heat rate, and fan and mill power were allproduced. While the magnitude of these improvements depend upon thespecific coal drying system configuration used, reductions in lignitemoisture content from 38.5% to 20% result in heat rate improvementswithin the 350-570 BTU/kWh (3.4-5.4%) range. Performance improvementsfor PRB coal are somewhat smaller, principally due to the fact that PRBcoal starts out with 30% moisture instead of the 38.5% moisture level oflignite coal.

Example V Pilot Dryer Coal Particle Segregation Results

During the Fall of 2003 and Summer of 2004, over 200 tons of lignite wasdried in a pilot fluidized bed coal dryer built by Great River Energy atUnderwood, N. Dak. The dryer capacity was 2 tons/hr and was designed fordetermining the economics of drying North Dakota lignite usinglow-temperature waste heat and determining the effectiveness ofconcentrating impurities such as mercury, ash and sulfur using thegravimetric separation capabilities of a fluidized bed.

Coal streams in and out of the dryer included the raw coal feed,processed coal stream, elutriated fines stream and the segregationstream. During tests, coal samples were taken from these streams andanalyzed for moisture, heating value, sulfur, ash and mercury. Some ofthe samples were sized and further analysis was done on various sizefractions.

The pilot coal dryer was instrumented to allow experimentaldetermination of drying rates under a variety of operating conditions. Adata collection system allowed the recording of dryer instruments on a1-minute bases. The installed instrumentation was sufficient to allowfor mass and energy balance calculations on the system.

The main components of the pilot dryer were the coal screen, coaldelivery equipment, storage bunker, fluidized bed dryer, air deliveryand heating system, in-bed heat exchanger, environmental controls (dustcollector), instrumentation, and a control and data acquisition systems(See FIG. 28). Screw augers were used for feeding coal in and productsout of the dryer. Vane feeders are used to control feed rates andprovide air lock on the coal streams in and out of the dryer. Load cellson the coal burner provided the flow rate and total coal input into thedryer. The segregation stream and dust collector elutriation werecollected in totes which were weighted before and after the test. Theoutput product stream was collected in a gravity trailer which wasequipped with a scale. The coal feed system was designed to supply¼-minus coal at up to 8000 lbs/hr to the dryer. The air system wasdesigned to supply 6000 SCFM @ 40 inches of water. An air heating coilinputted 438,000 BTU/hr and the bed coil inputted about 250,000 BTUs/hr.This was enough heat and air flow to remove about 655 lbs of water perhour.

Typical tests involved filling the coal bunker with 18,000 lbs of ¼″minus coal. The totes would be emptied and the gravity trailer scalereading recorded. Coal samples on the feed stock were collected eitherwhile filling the bunker or during the testing at the same time intervalas the dust collector, segregation stream and gravity trailer samples(normally every 30 minutes after achieving steady state.) The dustcollector and all product augers and air locks were then started. Thesupply air fan was started and set to 5000 scfm. The coal feed to thedryer was then started and run at high speed to fill the dryer. Once thebed was established in the dryer, the air temperature was increased,heating was lined up to the bed coil, and the air flow adjusted to thedesired value. The tests were then run for a period of 2-3 hours. Onetest was run for eight hours. After the test, the totes were weighed andthe gravity trailer scale reading recorded. Instrument reading from thetest was transferred to an excel spread sheet and the coal samples takento the lab for analysis. The totes and gravity trailer were then emptiedin preparation for the next test.

During the Fall of 2003, 150 tons of lignite was sent through thesingle-stage pilot dryer with a distributor area of 23.5 ft² in 39different tests. Coal was fed into the fluidized bed at rates between3000 to 5000 lbs/hr. Air flows were varied from 4400 (3.1 ft/sec) to5400 (3.8 ft/sec) scfm. The moisture reduction in the coal is a functionof the feed rate and the heat input to the drier. The 1^(st) pilotmodule had the ability to remove about 655 lb water per hour at thedesign water temperatures of 200° F. Feeding coal at 83.3 lbs/min, onewould expect a water removal rate of 0.13 lbs/lb coal.

During the Summer of 2004, the dryer was modified to two stages toimprove non-fluidized particle removal, and a larger bed coil wasinstalled. After modifying the dryer module, the drying capability wasincreased to about 750,000 BTU/hr with a water removal rate of 1100lbs/hr. An additional 50 tons of coal was dried in the new module. Themodified module also allowed for the collection of an segregation streamoff the 1^(st) stage. The segregation stream was non-fluidized materialwhich was removed from the bottom of the 1^(st) stage. It was primarilymade up of oversized and higher density material that wasgravimetrically separated in the 1^(st) stage. The total distributorplate area was 22.5 ft².

Table 2 shows the coal quality for the dryer feed, elutriation,segregation and product streams. The data indicates that the elutriationstream was high in mercury and ash, the segregation stream was high inmercury and sulfur, and the product stream experienced a significantimprovement in heating value, mercury, ash, and # SO₂/mBTUs. Theelutriation stream was primarily 40-mesh-minus and the segregationstream was 8-mesh-plus.

TABLE 2 Coal Feed Quality Verses Product Streams Test 44 Mercury HHVCoal Pounds ppb Ash % BTUs/lb Sulfur % #SO₂/mbtu Feed 14902 91.20 18.055830.00 0.53 1.82 Segregation 2714 100.61 15.41 6877.00 0.76 2.20 StreamElutriation 789 136.58 30.26 5433.75 0.50 1.86 Product 7695 65.83 14.227175.25 0.55 1.54Therefore, Test 44 reduced the mercury and sulfur in the coal productstream by 40% and 15%, respectively.

Time variation of bed temperature, measured at six locations within thebed, and outlet air temperature are presented in FIG. 29. Thisinformation was used, along with the information on coal moisturecontent (obtained from coal samples), to close the mass and energybalance for the dryer and determine the amount or removed moisture fromcoal.

FIG. 30 shows the makeup of the segregation stream product for the 7tests using the modified pilot dryer. Test 41 had the best results withthe segregation stream containing 48% of the sulfur and mercury and only23% of the Btu and 25% of the weight.

Example VI Some More Particle Segregation Results

Between September and December 2004, 115 tons of Canadian Lignite wasdried at the modified, two-stage pilot dryer located at Underwood, N.Dak. Between 3 and 20 tons of material was run through the dryer duringa daily test at flow rates of 2000-7000 lbs/hr. This produced coal withmoisture levels of 15-24% from a 31% moisture feed stock.

Load cells on the coal bunker provided the flow rate and total coalinput into the dryer. The segregation stream and dust collectorelutriation was collected into totes, which were weighed before andafter each test. The output product stream was collected in a gravitytrailer, which was equipped with a scale. The coal feed system wasdesigned to supply ¼-minus coal particles at up to 8000 lbs/hr to thedryer. The air system was designed to supply 6000 SCFM at 40 inches ofwater. An air heating coil input of 438,000 BTU/hr and a bed coil inputof about 500,000 BTU/hr were applied to the dryer. This was enough heatand air flow to remove about 900 pounds of water per hour, dependingupon ambient conditions and the temperature of the heating fluid.

The dryer output was typically 20% elutriation and segregation stream,and 80% product at 7000 lbs/hr flow rates with their percentageincreasing as the coal flow to the dryer was reduced. Samples werecollected off each stream during the tests and compared with the inputfeed. The segregation stream (“SS”) flow was typically set at 420-840lbs/hr. As the flow to the dryer was reduced, this became a largerpercentage of the output stream. The elutriation stream also tended toincrease as a percentage of the output as the coal flow was reduced.This was attributed to longer residence time in the dryer and higherattrition with lower moisture levels.

Typical tests involved filling the coal bunker with 18,000 pounds of¼-inch-minus coal. Lignite coal sourced from Canadian Mine No. 1 wasfirst crushed to 2-inch-minus. The material was then screened, placingthe ¼-inch-minus material (50%) in one pile and the ¼-inch-plus material(50%) in another pile. The pilot dryer was then filled by addingalternating buckets from the two piles. The ¼-inch-plus material was runthrough a crusher prior to being fed up to the bunker, and the¼-inch-minus material was fed in directly. Lignite coal sourced fromCanadian Mine No. 2 was run directly through a crusher and into thepilot bunker without screening. Coal samples on the feed stock werecollected from the respective stock piles. The dust collector (“DC”),segregation stream (“SS”), and gravity trailer (“GT”) samples were takenevery 30 minutes after achieving steady state. When running the largeamounts of the Mine No. 1 coal through the dryer, samples were takendaily with a grain probe on the gravity trailer, DC tote, and UC tote.

The totes were emptied and the gravity scale reading recorded. The dustcollector and all product augers and air locks were then started. Thesupply air fan was started and set to about 5000 SCFM. The coal feed tothe dryer was then started and run at high speed to fill the dryer. Oncethe bed was established in the dryer, the air temperature was increased,heating water lined up to the bed coil, and the air flow adjusted to thedesired value. The tests were then run for a period of 2-7 hours. Thebed was not always emptied between tests and the nominal 3000 pounds ofmaterial accounted for in the results.

Tables 3-4 tabulate the results of the Canadian Lignite tests. Table 3contains the dryer input, sum or the output streams, actual andcalculated, based upon the change in total moisture and the input. Table4 contains data on the three output streams for the Mine No. 1 CoalTests.

TABLE 3 Test Summary Actual Dryer Dryer Calculated Input Output DryerPercent Test (lbs) (lbs) Output (lbs) Difference Test 49 on Mine No. 26829 6088 6176 1.5 Coal Test 50 on Mine No. 2 6871 5840 5522 −5.4 CoalTest 52 on Mine No. 1 108,517 95,474 95,474 0 Coal Test 57 on Mine No. 138,500 33,206 32,931 −0.8 Coal Test 58 on Mine No. 1 7927 6396 6478 1.3Coal Test 59 on on Mine 27,960 25,320 25,278 −0.2 No. 1 Coal

TABLE 4 Mine No. 1 Coal Tests 52, 57, and 59 Results Tot. % % % % %Output Moisture BTU Output BTU Sulfur Mercury Ash 52DC 19.53 7117 10.19.26 8.54 14.24 14.21 52SS 20.3 7280 6.9 6.48 16.83 12.97 9.36 52GT21.93 7869 83.02 84.26 74.63 72.79 76.43 57DC 20.1 6019 8.62 7.11 5.6910.0 11.81 57SS 16.4 5321 10.85 7.90 41.52 44.23 20.78 57GT 19.65 771180.53 84.99 52.79 45.76 67.4 58DC 18.43 6721 7.60 6.54 5.35 8.70 9.6358SS 12.40 6375 18.96 15.48 45.38 44.03 33.49 58GT 16.09 8294 73.4477.98 49.28 47.27 56.88 59DC 23.24 6324 11.49 9.46 11.65 N/A 22.54 59SS30.14 6850 15.05 13.41 13.43 N/A 15.66 59GT 22.42 8069 73.46 77.13 74.92N/A 61.8

Tests 52, 57, 58, and 59 were conducted on the Mine No. 1 coal. Test 58was a controlled test, and for Tests 52, 57, and 59 the bunker was beingfilled with coal during the dryer operation.

Test 52 was conducted for the purpose of removing about 25% of the waterin the coal, and then bagging it for shipment to GTI for furthertesting. During this type of testing, we were filling the bunker at thesame time material was being fed into the dryer, thereby making itdifficult to track the input. For this test, the input was estimated bycorrecting the total output back to the coal feed total moisture. Test52 was conducted on six separate days over a three-week period. Afterthe second day of the test, the bed was not dumped, and the coalremained in the dryer for two-plus days in a fairly dry condition. Thiscoal started smoldering in the SS tote and in the dryer bed. When thedryer was started, ignition took place, and several of the explosionpanels needed to be replaced. The very dry condition of the coal and theperiod of time it sat, as well as the temperature of the bed when theunit was shut down contributed to this problem. We discontinued leavingcoal in the dryer bed without proper cool down, and for not longer thanone day. This seemed to eliminate the problem.

Tests 57, 58, and 59 were all one-day tests. During Tests 57 and 59,coal was added to the bunker during dryer operation, and we needed toestimate the coal feed. Test 57 was conducted at a coal inlet flow rateof about 7000 lbs/hr. Tests 58 and 59 were conducted at an inlet coalflow of about 5000 lbs/hr. The cooler temperature of early December hadreduced the dryer's capacity. The mercury analyzer malfunctioned duringTest 59.

The results of Table 4 provide good evidence that the segregation streamis capable of removing a significant amount of the sulfur and mercuryfrom the coal feed stream, while retaining the heat value of the coalfeed stream.

Example VII Prototype System Results

The prototype coal drying system employed at Coal Creek is based onusing waste heat from the steam condenser and hot flue gas to heat theair used for coal drying. The process flow diagram is presentedschematically in FIG. 60.

The prototype coal drying system and FBD were designed by a design teamassembled by Great River Energy (“GRE”). Fluidizing/drying air washeated indirectly by a source of hot water used to simulate thediversion of a portion of the hot cooling water from the main coolingwater stream and passing it through a water-to-air heat exchanger(fanroom coil) to increase the temperature of the air at the airpreheater (APH) inlet.

A portion of the primary air (PA) stream, referred to as the cold PAflow, was extracted from the main PA flow downstream of the fanroom coiland upstream from the APH. The rest of the PA flowed through the APHwhere its temperature is increased. A portion of the PA flow, referredto as the hot PA flow, was extracted downstream from the APH. Theremaining portion of the PA flowed to the coal mills.

The hot PA flowed through an air-to-water heat exchanger where itexchanged heat with the water which circulates through heat exchangersimmersed in the fluidized bed (in-bed heat exchangers). After exchangingheat with the circulating water, the warm PA was mixed with the cold PAin Mixing Boxes 1 and 2 (MB 1 and 2). The mixture of these two PAstreams formed a fluidizing/drying air stream for the first and secondstages of the coal dryer. With this prototype design, it was possible tovary the temperature of the fluidizing/drying air stream by changing theratio of the hot and cold PA flow streams.

This arrangement made it possible to increase the temperature of thefluidizing/drying air and the temperature of the hot circulating waterto the in-bed heat exchanger from the 110° F. level to 200° F. andhigher. This significant temperature increase had a large positiveeffect on the flow rate of fluidizing/drying air and FBD distributorsize, and the size of the in-bed heat exchanger, which were reduced astemperature of the fluidizing air and heat source is increased.

The hot PA flow required for the FBD flowed through the APH along withthe PA flow required for the mills. This increased the total PA flowand, in turn, the total air flow through the APH. As a result, the APHcooling capacity and the APH capacity rate ratio (the X-ratio)increased, and flue gas temperature at the APH outlet was lowered. Lowerexit flue gas temperature further improves boiler efficiency and unitperformance.

Coal feed for the dryer was supplied from existing coal bunker No. 28.The wet coal (feed stream) is fed by a vibrating coal feeder to a coalcrusher and crushed and sieved to −¼″. The crushed coal is screened by avibrating screen and conveyed to the dryer inlet hopper. Two rotary coalfeeders (air locks) fed coal to the first stage of the FBD. The screenbypass flow was mixed with a product stream leaving the dryer employinga bypass conveyer. Mixing of the two streams took place downstream ofthe coal sampling location.

The dried coal (product stream) leaving the dryer was stored in coalbunker No. 26, feeding coal mill 26. A coal conveyor and bucket elevatorwere used to transport dried coal to the No. 26 bunker. As productstream was transported from the dryer to the bunker, it cooled down, andits temperature dropped by approximately 10° F.

The prototype coal-drying system was designed in modular fashion toallow incremental drying of the coal. Each coal-drying module will dry aportion of the total coal flow and also included environmental controls(baghouse for dust control). With all four coal-drying modules inservice it will be possible to dry 100% of the coal feed.

Fluidization and heating of coal and removal of coal moisture wasaccomplished within the fluidized bed by hot fluidization air. The airstream was cooled and humidified as it flowed upwards through the coalbed. The quantity of moisture, which could be removed from the bed offluidized coal, was limited by the drying capacity of the fluidizationair stream. The drying capacity of the fluidization air stream could beincreased by supplying additional heat to the bed by the in-bed heatexchanger. The in-bed heat exchanger not only increased drying capacityof the fluidizing air stream but also it reduced the quantity of dryingair required to accomplish a desired degree of coal drying. Withsufficient in-bed heat transfer surface, the fluidizing/drying airstream could be reduced to the value corresponding to 1 to 1.2 m/ssuperficial fluidization velocity.

The prototype dryer design data are summarized in Table 5. The totaldistributor area was 308 ft², and the total in-bed heat exchanger areawas 8,636 ft². The dryer was fluidized by using 305 klbs/hr of air,resulting in a superficial fluidization velocity in the 1.0 to 1.2 m/srange.

As the data in Table 5 show, the heat transfer area for individual bedcoils, depending on their design, varied from 1,144 to 1,982 ft². Theaverage heat transfer coefficient for finned tubes of 18 Btu/hr-ft²-° F.was determined experimentally by GRE and Barr engineers.

TABLE 5 Prototype Dryer Design Data Prototype Coal Dryer PrototypeParameter Units Value Distributor Area ft² 308 First Stage FluidizingAir Flow klbs/hr 55 Second Stage Fluidizing Air Flow klbs/hr 250Expanded Bed Depth ″ 38 to 40 In-Bed Heat Exchanger No. 1 HT Area ft²1,982 In-Bed Heat Exchanger No. 2 HT Area ft² 1,696 In-Bed HeatExchanger No. 3 HT Area ft² 1,982 In-Bed Heat Exchanger No. 4 HT Areaft² 1,832 In-Bed Heat Exchanger No. 5 HT Area ft² 1,144 Total In-BedHeat Exchnager Area ft² 8,636 Total Exchanged Heat, In-Bed HXE MBTU/hr16.53 Average Heat Transfer Coefficient BTU/hr-ft²-° F. 18.08 TotalWater Flow Through the In-Bed Heat gpm 1,588 Exchangers, Actual TotalWater Flow Through the In-Bed Heat gpm 1,363 Exchangers, Indicated

The flow rate of circulating water through all bed coils, measured by atest-grade flow meter, was approximately 1,600 gpm (758 klbs/hr). Thevalue indicated by the plant flow meter was approximately 14% lower(i.e., 650 klbs/hr).

Sixteen dryer performance tests were performed during time period fromMar. 22^(nd) to May 12^(th) 2006, under controlled conditions with abaseline coal feed rate of 75 t/hr, fluidization air temperature in the165 to 190° F. range, and average bed coil temperature of 210° F. Underthese operating conditions, in-bed heat input to the dryer was in the 15to 16 MBtu/hr range.

A comparison of measured and predicted (simulated) dryer performance ispresented in FIGS. 61 and 62. The total moisture content measured in theproduct stream is presented in FIG. 61 as a function of fluidization airtemperature. Dryer simulation results are represented by a solid line.As FIG. 61 shows, there is a very good agreement between the measuredand predicted product moisture contents. The results also show that theprototype dryer was operated with a relatively low fluidization airtemperature. Increasing the fluidization temperature will have apositive effect on dryer performance.

FIG. 62 compares the measured and predicted coal moisture reduction inthe prototype dryer. Except for a few test points, there is very goodagreement between the measurements and simulation. The target moistureremoval level, of 8.45%, was easily reached by operating the prototypedryer with fluidization temperature at or above 180° F.

The total coal moisture (TM) and higher heating value (HHV) measured inthe feed and product streams during the controlled dryer tests aresummarized in Table 6 and presented in FIGS. 63 and 64. The Test 16results show a much lower TM content and higher HHV value compared tothe other tests and were, therefore, not included in the statisticalanalysis of data. The results show that average moisture reduction was8.08±0.42%. The HHV was on average improved by 727±62 Btu/lb. The randomerror in Table 6 represents the 95% confidence interval. The variationin TM and HHV during the controlled tests is presented in FIGS. 63 and64. The improvement in HHV and reduction in total coal moisture contentare presented in FIG. 65.

TABLE 6 Dryer Performance Tests: Coal Moisture and HHV CD 26 TM [%] TM[%] TM [% Abs] Dry Coal Flow HHV [BTU/lb] HHV [BTU/lb] ΔHHV [BTU/lb]Test Number Product Feed Reduction % of Total Product Feed Difference 127.98 37.03 9.05 14.28 6,871 6,203 668 2 29.08 36.74 7.66 14.28 6,7466,148 598 3 29.21 37.44 8.22 13.79 7,069 6,392 677 4 28.77 36.76 7.9913.91 7,037 6,292 745 5 30.87 37.50 6.63 13.32 7,028 6,172 857 6 27.2236.58 9.36 13.84 7,212 6,214 997 7 29.10 37.44 8.34 14.28 7,162 6,392770 8 27.63 36.99 9.36 14.29 6,947 6,337 610 9 29.88 36.98 7.09 14.267,033 6,489 544 10 29.10 37.07 7.97 14.14 7,109 6,361 748 11 28.37 36.007.63 14.29 7,084 6,270 814 12 29.00 37.16 8.16 14.29 7,035 6,340 695 1329.34 37.34 8.00 14.29 7,060 6,285 775 14 29.17 37.03 7.86 14.29 6,8546,176 679 15 29.91 37.81 7.90 14.29 7,145 6,415 730 16 21.19 37.47 16.2813.90 7,499 6,440 1,059 Average 28.98 37.06 8.08 14.12 7,026 6,299 727Std. Dev 0.92 0.44 0.75 0.29 125 102 112 St. Error 0.24 0.11 0.19 0.0732 26 29 Random Error 0.51 0.24 0.42 0.16 69 56 62 Note: The data fromTest 16 are considered outliers and are not included in the calculatedaverage and standard deviation values.

Coal quality data were collected during regular dryer operation for thetime period from March to April, 2006. Results are presented in Table 7and FIGS. 66 and 67.

TABLE 7 Regular Dryer Performance: Coal Moisture and HHV Feed ProductChange Change Parameter TM % TM % TM % Abs TM % Rel Average TotalMoisture, 36.78 28.55 8.23 22.4 TM Std. Deviation 1.26 1.00 1.07 Std.Deviation of the Mean 0.34 0.27 0.30 Feed Product Change HHV HHV HHVChange Parameter [BTU/lb] [BTU/lb] [BTU/lb] HHV [%] Average HHV 6,2907,043 752 12.0 Std. Deviation 159 121 131 Std. Deviation of the 43 33 37Mean

The average moisture reduction, achieved during regular dryer operation,was 8.23±0.6 percent. This is almost identical to the total moisturereduction achieved during the controlled performance tests. Theimprovement in HHV during regular dryer operation was 752±74 Btu/lb.Within the accuracy of the data, this is the same improvement in HHVachieved during the controlled dryer performance tests. This means thatdryer performance, measured during the controlled tests, is sustainableover the long-term.

The maximum design coal feed rate for the prototype dryer is 112.5 tonsper hour. With four dryers in service, each operating at the maximumfeed rate, it would be possible to dry the total full-load coal feed forUnit 2 at Coal Creek (450 t/hr).

Three maximum capacity tests (CT1, CT2, and CT3) were performed fromJun. 21 to 23, 2006, where coal feed rate was increased from thebaseline value of 75 t/hr first to 90 t/hr, and finally to the maximumvalue of 101 t/hr. The coal conveying system and dust collector fanpower imposed a limit on the maximum coal feed rate, which felt short ofthe design value by 10%.

The maximum capacity test data are summarized in Tables 8-10. Operatingconditions of the dryer, presented in Table 8, show that inlettemperatures of fluidizing air and circulating water were increasedabove the baseline values to accommodate higher coal feed to the dryer.With the maximum coal feed rate at 101 t/hr, fluidization airtemperature was 40° F. higher compared to baseline operation, while thecirculating water temperature was 20° F. higher. This was accomplishedby increasing hot PA flow to the mixing boxes 1 and 2. With the feedrate at 101 t/hr, the dried coal represented 21% of the total coal feedto the boiler.

TABLE 8 Maximum Capacity Tests -- Dryer Operating Conditions Dryer TotalCirculating Circulating Test Coal Coal Fluidization Fluidization WaterInlet Water Outlet In-Bed Heat Duration Feed Flow Dried Coal Air FlowTemperature Temperature Temperature Transfer Test Date hours t/hr t/hr %of Total klbs/hr ° F. ° F. ° F. MBTU/hr 1 Jun. 21, 2006 4 90 494.0 18.2301 188 219 200 15.1 2 Jun. 22, 2006 4 90 484.5 18.6 291 214 233 21116.4 3 Jun. 23, 2006 2 101 480.5 21.0 288 220 236 214 16.9

TABLE 9 Maximum Capacity Tests -- Coal Moisture Reduction Coal DryerCoal Feed to the Boiler Feed Product Moisture Moisture Average CoalMoisture Coal Feed Moisture Moisture Reduction Reduction MoistureReduction Test t/hr % % % Abs % Rel % % Abs 1 90 35.2 27.9 7.3 20.7 33.91.3 2 90 36.8 27.4 9.4 25.5 35.1 1.7 3 101 36.4 29.1 7.3 20.1 34.9 1.5

TABLE 10 Maximum Capacity Tests -- Improvement in HHV Coal Dryer CoalFeed to the Boiler Product HHV HHV Average Coal HHV HHV Coal Feed FeedHHV HHV Increase Increase HHV Improvement Improvement Test t/hr BTU/lbBTU/lb BTU/lb % BTU/lb BTU/lb % 1 90 5,895 6,886 991 16.8 6,076 181 3.12 90 6,198 7,074 876 14.1 6,361 163 2.6 3 101 6,116 7,393 1,277 20.96,384 268 4.4

The reduction in coal moisture, achieved in the maximum capacity tests,is summarized in Table 9. The results show that the coal moisturereduction in the 7 to 9 percentage point range (20-26% relative) wasachieved. The average coal moisture in the coal feed to the boiler(blend of dried and wet coal), was in the 1.3-1.7% range.

The coal HHV improved as moisture was removed from the coal in theprototype coal dryer, as shown in Table 10. The achieved HHV improvementwas in the 875 to 1,280 Btu/lb range, or 14 to 21%. The improvement inthe HHV of the boiler coal feed was in the 160 to 270 Btu/lb range, orfrom 2.6-4.4%.

The non-fluidizable material sunk to the bottom of the first dryerstage, and was removed from the dryer as the segregation stream by anmechanically-driven auger and a system of locks, gates and scrubbingboxes. Samples were taken from the segregation stream and analyzed todetermine its composition. Results are presented in Tables 11 and 12 andin FIGS. 68 through 71 for baseline coal feed flow rate.

The total moisture, sulfur, and mercury content, and HHV of the feed,product, and segregation streams, determined from samples that werecollected during the May-June time period, are summarized in Table 11.While the total moisture content of the product stream was significantlylower and its HHV higher compared to the feed stream, the moisturecontent and HHV of the undercut stream were similar to the feed stream.These experimental findings are in agreement with the dryer simulationresults that show that only 10% of the total moisture removed in thedryer is removed in the first stage.

Table 12 presents the sulfur, mercury, and HHV of the segregation streamas percentages of the feed stream. The results show that approximately30% of sulfur and mercury in the feed stream entering the dryer wereremoved in the first stage and discharged as the segregation stream. Thesegregation stream also contained approximately 10% of the inlet HHV.Additional processing of the segregation stream was needed to furtherconcentrate sulfur and mercury and reduce the HHV content. Segregationstream processing will be incorporated into the commercial coal dryingsystem.

The segregation stream samples were also collected during the maximumdryer capacity tests. During these tests, the gate cycling time wasparametrically varied from 7 to 15 seconds to improve segregationcharacteristics of the first stage.

TABLE 11 Composition of Feed, Product and Segregated Streams (May-June,2006) Feed Stream Product Stream Segregation Stream HHV TM Sulfur Hg ppmHHV TM Sulfur Hg ppm HHV TM Sulfur Hg ppm Test BTU/lb % % AR AR BTU/lb %% AR AR BTU/lb % % AR AR 1 6,359 38.1 0.61 614 7,477 28.1 0.60 498 6,63135.7 1.37 1,347 2 6,303 37.2 0.69 700 7,448 27.1 0.60 380 6,263 35.32.00 1,853 3 6,271 38.1 0.63 500 7,363 25.3 0.62 463 6,097 33.9 2.162,290 4 6,324 37.3 0.66 648 7,565 23.2 0.60 615 6,504 37.2 1.39 1,509 56,370 37.8 0.58 495 7,840 23.2 0.67 493 6,696 37.1 1.13 1,246 6 6,11537.3 0.55 616 7,796 21.0 0.61 555 6,223 35.0 1.97 2,237 7 6,085 36.80.61 748 7,434 25.1 0.60 553 6,267 34.7 1.71 1,839 8 6,236 37.0 0.61 6257,583 28.6 0.55 457 6,389 36.0 1.58 1,970 9 6,421 38.1 0.57 604 7,30328.3 0.63 536 6,427 35.9 1.85 2,537 10 6,303 38.2 0.69 591 7,335 28.80.65 606 6,558 36.1 1.89 2,121

TABLE 12 Sulfur and Mercury Removed by the First Stage and HHV Contentof the Segregated Stream Segregated Stream S Hg % of % of HHV Test FeedFeed % of Feed 1 22.5 21.9 10.4 2 29.3 26.5 9.9 3 34.5 45.8 9.7 4 21.223.3 10.3 5 19.4 25.2 10.5 6 36.0 36.3 10.2 7 28.2 24.6 10.3 8 25.7 31.510.2 9 32.5 42.0 10.0 10  27.4 35.9 10.4 Average 27.7 31.3 10.2

The NO_(x) and SO_(x) emissions, flue gas flow rate, and flue gas CO₂composition, measured by the plant CEM for 16 paired performance tests,are summarized in Table 13. As discussed earlier, firing partially driedcoal resulted in lower flue gas flow rate. For the coal moisturereduction of 1.14%, achieved in the dryer performance tests, thereduction in flue gas mass flow rate was 0.55%.

TABLE 13 NO_(x) and SO_(x) Emissions, Stack Flow Rate, and Flue Gas CO₂Concentration Measured by the Plant CEM Mass- Absolute Average Average %Change Change Description Units Dry Wet WRT Wet WRT Wet NOx Emissionslbs/hr 1,359 1,469 −7.52 −111 SOx Emissions lbs/hr 3,641 3,670 −0.81 −30Flue Gas Flow kscfm 1,613 1,625 −0.73 −12 Rate Flue Gas Flow klbs/hr7,101 7,140 −0.55 −39 Rate Flue Gas CO2 % 11.90 11.87 0.27 0

The 7.5% average reduction in NO_(x) mass emissions, measured during thepaired performance tests (FIG. 72), was significantly higher than thepercentage reduction in flue gas flow rate. This reduction in NO_(x)emissions cannot be explained by a lower flue gas flow rate. Instead itis attributed to a lower primary air flow rate to Mill No. 26, which washandling partially dried coal. From combustion optimization tests,performed by the ERC and GRE engineers at Coal Creek in 1997, it isknown that NO_(x) emissions at this plant are quite sensitive to theprimary air flow; NO_(x) decreases as primary air flow is reduced. Withpartially dried coal, the primary air flow rate to the No. 26 mill was,on average, reduced from 355 to 310 klbs/hr, a 12% reduction.Modifications to the coal mills will allow the primary air flow to bedecreased even more to 255 klbs/hr. This is expected to result in afurther decrease in NO_(x) emissions.

With the commercial coal drying system in service, i.e., with 100% driedcoal delivered to the coal mills, and the reduced PA flows to the mills,the reduction in NO_(x) emissions is expected to exceed 10%.

The measured reduction in SO_(x) emissions with partially dried coal,measured during the series of 16 paired parametric tests, wasapproximately 0.8% (Table 14 and FIG. 73). The red bar in Test 14represents a bad reading.

A closer inspection of the recorded plant data and the results presentedin FIG. 73 points to problems with SO_(x) measurement that occurredduring tests 12 to 14, where measured SO_(x) emissions were higher witha partially dried coal compared to the wet coal. These inconsistenciesare explained by a malfunctioning SO_(x) monitor that was providingunreliable SO_(x) readings for tests 12 to 14. A comparison of theresults for the first 11 paired tests and for all 16 paired tests showsa significant difference in SO_(x) reduction (1.9% for the first 11tests vs. 0.8% for all 16 tests). It is, therefore, reasonable to assumethat the actual reduction in SO_(x) emissions, achieved with partiallydried coal, is in the 1.9% range.

The percentage reduction in SO_(x) emissions is larger than thepercentage the reduction in flue gas mass flow rate. This is becausewith a lower flue gas flow rate, the flue gas bypass around the scrubberdecreases (CCS is a partially scrubbed unit), resulting in a higherSO_(x) removal. With 100% partially dried coal fired in the boiler, theflue gas flow rate to the wet scrubber will be reduced by an estimated4%. Combined with lower APH leakage, that would be achieved by usingdouble-edge APH seals, the percentage of the scrubbed flue gas flow willfurther increase, approaching a zero scrubber bypass configuration. Thiswill result in an additional reduction in SO_(x) emissions.

Due to a gravitational separation that is taking place in the firstdryer stage, the sulfur concentration in the segregation stream is threetimes higher compared to the product and feed streams. This increase insulfur content in the segregation stream can be explained by the factthat pyrites, having higher density than coal, are segregated out in thefirst dryer stage. For the present configuration of the prototype coaldrying system at CCS, the segregation stream is returned to and mixedwith the product stream from the coal dryer. Therefore, the benefit ofsulfur removal in the first dryer stage, is not being realized, and themeasured reduction in SO_(x) emissions is solely due to the lower fluegas and scrubber bypass flows.

The commercial coal drying system is designed to further process thesegregation stream. After processing, the segregation stream will not bemixed with the product stream from the commercial dryers. With thesegregation stream representing 5-10% of the dryer feed, the reductionin mass flow rate of sulfur to the boiler would be in the 7-12% range.By combining reductions due to the lower scrubber bypass and lowersulfur input to the boiler, the potential reduction in SO_(x), emissionsthat could be achieved with the commercial coal drying system at CCSoperating at 100% capacity is expected to be in the 12-17% range.

The reduction in CO₂ mass emissions is proportional to the improvementin unit performance (net unit heat rate). For the target moisturereduction of 8.5% and fanroom coils in service, the expected reductionin CO₂ emissions is approximately 2.4%.

The reduction in Hg emissions, achieved during paired performance testsat CCS, is proportional to the improvement in unit performance, and isestimated to be in the 0.4% range.

The segregation stream from the first dryer stage contains approximately3.5 to 4 times more Hg compared to the product and feed streams (seeFIGS. 74-75). This increase in Hg content in the segregation stream canbe explained by the fact that for the Falkirk lignite, a significantportion of mercury is bound to pyrites that are segregated out in thefirst dryer stage.

With the present configuration of the prototype coal drying system atCCS, the segregation stream is returned to the product stream from thecoal dryer. Therefore, the benefit of Hg removal in the first dryerstage on Hg emissions is not realized.

The commercial coal drying system is designed to further process thesegregation stream. After processing, the segregation stream will not bemixed with the product stream from the commercial dryers and will not beburned in the CCS boiler. With the segregation stream representing 5 to10% of the dryer feed, the estimated reduction in mass flow rate ofmercury to the boiler is in the 13-25% range (see FIGS. 74-75).

Mercury speciation is, among many other factors, affected by flue gasmoisture content and residence time. With the target moisture removal of8.5%, the flue gas moisture content is 2.5 percentage points lowercompared to that with wet coal. According to the theoretical gas-phaseresults shown in FIG. 76, this would result in approximately a 20%reduction in elemental mercury, Hg^(o), in the flue gas. Expresseddifferently, with a partially dried coal, approximately 20% moreelemental mercury will be oxidized compared to the wet coal. Theoxidized mercury, Hg⁺², is water soluble and can be removed in the wetscrubber.

Also, an increase in residence time has a positive effect on mercuryoxidation. This effect is, however, small, of the order of one percentper one second increase in residence time. With a partially dried coal,the residence time will increase due to lower flow rates.

The total vapor phase mercury concentration at CCS is in the 15 to 18microgram/Nm³ range. This compares favorably to flue gas Hgconcentrations calculated from the mercury content in coal and flue gasflow rate. Also, approximately 65% (12 microgramsg/Nm³) of the vaporphase mercury at CCS is elemental mercury, Hg^(o), Assuming a 20%relative reduction in elemental mercury due to lower flue gas moisturecontent and increased residence time, the reduction in Hg^(o) in fluegas stream would be 13%, or approximately 2.3 micro g/Nm³, assuming 98%Hg removal in the wet scrubber.

By combining a reduction in coal mercury content due to gravitationalseparation in a fluidized bed coal dryer (13-25%), and reduction inHg^(o) due to the lower flue gas moisture content (13%), the totalreduction in Hg emissions that could be achieved at CCS with thecommercial coal drying system operating at 100% capacity, is predictedto be in the 25-35% range.

The above specification, drawings, and examples provide a completedescription of the structure and operation of the particulate materialseparator of the present invention. However, the invention is capable ofuse in various other combinations, modifications, embodiments, andenvironments without departing from the spirit and scope of theinvention.

For example, it can be utilized with any combination of direct orindirect heat source, fluidized or non-fluidized beds, and single ormultiple stages. Moreover, the drying approach described in thisinvention is not limited to enhancing the quality of coal to be burnedin the utility or industrial boilers but can also be applied to dryparticulate materials for the glass, aluminum, pulp and paper and otherindustries. For example, sand used as a feedstock in the glass industrycan be dried and preheated by a fluidized bed dryer using waste heatharvested from flue gas exiting the furnace stack before the sand is fedto the glass furnace. This will improve thermal efficiency of theglass-making process.

As another example, a fluidized bed dryer can be used as a calcinatoryin aluminum production. To refine alumina from raw bauxite ore, the oreis broken up and screened when necessary to remove large impurities likestone. The crushed bauxite is then mixed in a solution of hot causticsoda in digesters. This allows the alumina hydrate to be dissolved fromthe ore. After the red mud residue is removed by decantation andfiltration, the caustic solution is piped into huge tanks, calledprecipitators, where alumina hydrate crystallizes. The hydrate is thenfiltered and sent to calciners to dry and under very high temperature,is transformed into the fine, white powder known as alumina. The presentinvention could be used as a calciner in this and similar processes.

As still another example for purposes of illustration, waste heatsources could be applied to a greenhouse used to grow tomatoes or othercrops. Therefore, the description is not intended to limit the inventionto the particular form disclosed.

Therefore, the description is not intended to limit the invention to theparticular form disclosed.

1. An open air apparatus for segregating particulate material by densityand/or size to concentrate a contaminant for separation from theparticulate material feed stream, comprising: (a) a fluidizing bedhaving a receiving inlet for receiving the particulate material feed, aninlet opening for receiving a fluidizing stream, a first dischargeoutlet for discharging a fluidized particulate material product stream,and a second discharge outlet for discharging a non-fluidizedparticulate material stream; (b) a source of fluidizing stream at atemperature of about 300° F. or less operatively connected to the inletopening for introducing the fluidizing stream into the fluidizing bed toachieve separation of the fluidized particulate material product streamfrom the non-fluidized particulate material stream; (c) a conveyor meanslocated within the fluidized bed for transporting the non-fluidizedparticulate material from inside the fluidized bed to the outside of thefluidized bed through the second discharge outlet; and (d) wherein thefluidized particulate material product stream contains a reduction inthe contaminant relative to the particulate material feed stream, andthe non-fluidized particulate material stream contains an increase inthe contaminant relative to the particulate material feed stream.
 2. Theparticulate material segregating apparatus of claim 1, wherein theparticulate material is coal.
 3. The particulate material segregatingapparatus of claim 2, wherein the coal material is lignite coal.
 4. Theparticulate material segregating apparatus of claim 2, wherein the coalmaterial is subbituminous coal.
 5. The particulate material segregatingapparatus of claim 2, wherein the contaminant is selected from the groupconsisting of fly ash, sulfur, mercury, and ash.
 6. The particulatematerial segregating apparatus of claim 5, wherein the non-fluidizedcoal particulate material stream contains about 21-46% of the mercuryoriginally contained in the coal particulate material feed stream, whichis removed from the fluidized coal particulate product stream.
 7. Theparticulate material segregating apparatus of claim 5, wherein thenon-fluidized coal particulate material stream contains about 19-36% ofthe sulfur originally contained in the coal particulate material feedstream, which is removed from the fluidized coal particulate productstream.
 8. The particulate material segregating apparatus of claim 5,wherein the non-fluidized coal particulate material stream containsabout 23-43% of the fly ash originally contained in the coal particulatematerial feed stream, which is removed from the fluidized coalparticulate product stream.
 9. The particulate material segregatingapparatus of claim 2, wherein the coal of the fluidized particulatematerial product stream, when combusted, produces a flue gas having areduction in SO_(x) of about 4%.
 10. The particulate materialsegregating apparatus of claim 2, wherein the coal of the fluidizedparticulate material product stream, when combusted, produces a flue gashaving a reduction in NO_(x) of about 10%.
 11. The particulate materialsegregating apparatus of claim 1, wherein the fluidizing stream is air.12. The particulate material segregating apparatus of claim 1, whereinthe fluidizing stream is steam.
 13. The particulate material segregatingapparatus of claim 1, wherein the fluidizing stream is an inert gas. 14.The particulate material segregating apparatus of claim 1, wherein thefluidizing stream is heated by a heat source prior to its introductionto the fluidizing bed.
 15. The particulate material segregatingapparatus of claim 14, wherein the heat source is a principal heatsource.
 16. The particulate material segregating apparatus of claim 14,wherein the heat source is a waste heat source.
 17. The particulatematerial segregating apparatus of claim 16, wherein the waste heatsource is selected from the group consisting of hot condenser coolingwater, hot stack gas, hot flue gas, spent process steam, and discardedheat from operating equipment.
 18. The particulate material segregatingapparatus of claim 1 further comprising a collection chamber operativelyconnected to the non-fluidized particulate material stream seconddischarge outlet for receiving the non-fluidized particulate materialstream, the collection chamber including a second fluidizing bed andmeans for directing a second fluidizing stream through the non-fluidizedparticulate material contained within the collection chamber forseparating fluidizable particles therefrom to further concentrate thecontaminant within the non-fluidized particulate material stream. 19.The particulate material segregating apparatus of claim 18, wherein thefluidizable particles separated from the non-fluidized particulatematerial stream in the collection chamber are returned to the fluidizingbed by a second fluidizing stream.